Item 1.
Business.
Our Partnership
We are a growth-oriented Delaware limited partnership formed in March 2006 and are engaged in the business of gathering, compressing, treating, processing, transporting and selling natural gas and fractionating and transporting natural gas liquids, or NGLs. Our assets are strategically located in three significant natural gas producing regions in the Texas Panhandle, southeast Texas and Louisiana. We intend to acquire and construct additional assets, and we have an experienced management team dedicated to growing and maximizing the profitability of our assets.
On October 24, 2006, we completed our initial public offering, or IPO. We issued 12,500,000 common units to the public, representing a 29.6% limited partner interest. Eagle Rock Holdings, L.P., upon contribution of certain assets and ownership of operating subsidiaries, received 3,459,236 common units and 20,691,495 subordinated units, totaling an aggregate initially of 57.2% limited partner interest (which reduced to 54.0% after the exercise of the overallotment option and including restricted common units issued to employees in connection with our IPO), and all of the equity interests in the Partnership’s general partner, Eagle Rock Energy GP, L.P., which owns a 2% general partner interest. Additional private investors, after conversion of their ownership in Eagle Rock Pipeline, L.P., received 4,732,259 common units, representing initially an 11.2% limited partner interest in the Partnership (which reduced to 10.7% after the exercise of the overallotment option and including restricted common units issued to employees in connection with our IPO). On November 21, 2006, 1,463,785 common units were redeemed as part of the exercise of the underwriters’ overallotment option we granted in conjunction with our IPO. In connection with the IPO, Eagle Rock Pipeline, L.P. was merged with and into our newly formed subsidiary with Eagle Rock Pipeline, L.P. being the surviving entity.
The net proceeds from the offering of approximately $219.1 million, after deducting underwriting discounts and fees and offering expenses, were used for the following: (i) to replenish approximately $35.0 million of working capital distributed prior to the consummation of the offering to the existing equity owners of Eagle Rock Pipeline, L.P., (ii) to satisfy our obligation to reimburse Eagle Rock Holdings and certain private investors for approximately $173.1 million of capital expenditures incurred prior to the IPO related to the assets contributed to the Partnership and as partial consideration for the contribution of those assets, and (iii) to distribute approximately $11.0 million to Eagle Rock Holdings as a cash distribution from Eagle Rock Pipeline, L.P. in respect of arrearages on the existing subordinated and general partner units of Eagle Rock Pipeline, L.P. owned by Eagle Rock Holdings. In addition, a portion of the proceeds were used to reimburse the Partnership for transaction costs of the offering.
As a result of the initial public offering, our current partnership structure is such that Eagle Rock Energy G&P, LLC is the general partner of Eagle Rock Energy GP, L.P., which is the general partner of Eagle Rock Energy Partners, L.P. Eagle Rock Holdings, L.P., which is owned by members of management and private equity funds controlled by Natural Gas Partners, is the sole member of Eagle Rock G&P, LLC.
Our Texas Panhandle operations cover ten counties in Texas and one county in Oklahoma, consisting of our East Panhandle System and our West Panhandle System (collectively, “Texas Panhandle Systems”). The facilities that comprise our East Panhandle System are primarily located in Wheeler, Hemphill and Roberts Counties in the eastern Texas Panhandle and consist of:
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approximately 773 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 35,289 horsepower of associated pipeline compression;
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three active natural gas processing plants with an aggregate capacity of 90 MMcf/d; and
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two natural gas treating facilities with an aggregate capacity of 75 MMcf/d.
The facilities that comprise our West Panhandle System are primarily located in Moore, Potter, Hutchinson, Carson, Roberts, Gray, Wheeler and Collingsworth Counties in the western Texas Panhandle and consist of:
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approximately 2,736 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 81,473 horsepower of associated pipeline compression;
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four active natural gas processing plants with an aggregate capacity of 101 MMcf/d;
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three natural gas treating facilities with an aggregate capacity of 65 MMcf/d;
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a propane fractionation facility with capacity of 1,000 Bbls/d; and
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a condensate collection facility.
Our southeast Texas and Louisiana operations (“Texas and Louisiana System”) are primarily located in Polk, Tyler, Jasper and Newton counties, Texas and Vernon Parish, Louisiana. The facilities that comprise our southeast Texas and Louisiana System consist of:
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approximately 1,049 miles of natural gas gathering pipelines, ranging from four inches to 12 inches in diameter, with 5,200 horsepower of associated pipeline compression;
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a 100 MMcf/d cryogenic processing plant;
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a 150 MMcf/d cryogenic processing plant, in which we own a 25% undivided interest; and
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a 19-mile NGL pipeline.
We commenced operations in 2002 when certain members of our management team formed Eagle Rock Energy, Inc., an affiliate of our predecessor, to provide midstream services to natural gas producers. Since 2002, we have grown through a combination of organic growth and acquisitions. In connection with the acquisition in 2003 of the Dry Trail plant, a CO2 tertiary recovery plant located in the Oklahoma panhandle, members of our management team formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets. Eagle Rock Holdings, L.P., has benefited from the equity sponsorship of Natural Gas Partners, one of the largest private equity fund sponsors of companies in the energy sector, which since 2003 has provided us with significant support in pursuing acquisitions.
Business Strategies
Our primary business objective is to increase our cash distributions per unit over time. We intend to accomplish this objective by continuing to execute the following business strategies:
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Maximizing the profitability of our existing assets. We intend to maximize the profitability of our existing assets by adding new volumes of natural gas and undertaking additional initiatives to enhance utilization and improve operating efficiencies. We plan to:
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market our midstream services and provide superior customer service to producers in our areas of operation to connect new wells to our gathering and processing systems, increase gathering volumes from existing wells and more fully utilize excess capacity on our systems; and
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improve the operations of our existing assets by relocating idle processing plants to areas experiencing increased processing demand, reconfiguring compression facilities, improving processing plant efficiencies and capturing lost and unaccounted for natural gas.
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Expanding our operations through organic growth projects. We intend to leverage our existing infrastructure and customer relationships by expanding our existing asset base to meet new or increased demand for midstream services. We completed the construction of our Tyler County pipeline in the March 2006 quarter and will complete a 16-mile extension in the first half of 2007 that will allow for the delivery of dedicated natural gas volumes to our Brookeland processing plant. We will complete in
the second quarter of 2007 the refurbishment project of restarting the Red Deer plant in our Texas Panhandle Systems which will provide needed additional gas processing capacity.
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Pursuing complementary acquisitions. We have grown significantly through acquisitions and will continue to employ a disciplined acquisition strategy that capitalizes on the operational experience of our management team as well as bring new expertise to the Partnership. We believe that the extensive experience of our management team in acquiring and operating natural gas gathering and processing assets will enable us to continue to successfully identify and complete acquisitions that will enhance our profitability and increase our operating capacity.
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Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk. We instituted a hedging program related to our NGL business and have hedged substantially all of our share of expected NGL volumes through 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts, and substantially all of our share of expected NGL volumes related to our percentage-of-proceeds contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. We have also hedged substantially all of our share of our short natural gas position for 2006 and 2007. We anticipate that after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our acquisition of the Brookeland and Masters Creek systems. In addition, where market conditions permit, we intend to pursue fee-based arrangements and to increase retained percentages of natural gas and NGLs under percent-of-proceeds arrangements.
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Maintaining a disciplined financial policy. We will continue to pursue a disciplined financial policy by maintaining a prudent capital structure, managing our exposure to interest rate and commodity price risk and conservatively managing our cash reserves. We are committed to maintaining a balanced capital structure, which will allow us to use our available capital to selectively pursue accretive investment opportunities.
Competitive Strengths
We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:
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Our assets are strategically located in major natural gas supply areas. Our assets are strategically located in the Texas Panhandle, southeast Texas and Louisiana. Our Texas Panhandle Systems are located in areas that produce natural gas with high NGL content, especially in the West Panhandle System. Our East Panhandle System is experiencing significant drilling activity related to the Granite Wash play and our West Panhandle System is connected to wells that generally have long lives with predictable, steady flow rates and minimal decline. Additionally, our southeast Texas and Louisiana assets, specifically in Tyler and Polk Counties, are located in areas characterized by high volumes of natural gas and significant drilling activity, which provides us with attractive opportunities to access newly developed natural gas supplies. We believe that our extensive existing presence in these regions, together with our available capacity and the limited alternatives available to local producers, provide us with a competitive advantage in capturing new supplies of natural gas.
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We provide a distinct and integrated package of midstream services. We provide a broad range of midstream services to natural gas producers, including gathering, compressing, treating, processing, transporting and selling natural gas and fractionating and transporting NGLs. For example, in the Texas Panhandle, we treat natural gas to extract impurities such as carbon dioxide and hydrogen sulfide and we fractionate NGLs to extract propane. Our competitors in this area do not provide these services. Additionally, many of our gathering systems, including our Texas Panhandle Systems, operate at lower inlet pressures, which allow us to provide gathering services to customers at a lower cost and on a more timely basis than our competitors, who are often required to add compression to provide gathering services to new wells.
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We have the financial flexibility to pursue growth opportunities. We currently have approximately a $500.0 million amended and restated credit facility, under which we have approximately $80.0 million unused capacity, with $24.0 million available capacity at year end. We believe the available capacity under this credit facility, combined with our expected ability to access the capital markets, will provide us with a flexible financial structure that will facilitate our strategic expansion and acquisition strategies.
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We have an experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through the investment in, and the acquisition, exploitation and integration of, natural gas midstream assets. Our senior management team has an average of over 25 years of industry-related experience. Our team’s extensive experience and contacts within the midstream industry provide a strong foundation for managing and enhancing our operations, accessing strategic acquisition opportunities and constructing new assets. Members of our senior management team have a substantial economic interest in us.
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We are affiliated with Natural Gas Partners, a leading private equity capital source for the energy industry. Natural Gas Partners, a leading private equity firm focused on the energy industry, owns a significant equity position in Eagle Rock Holdings, L.P., which owns 2,187,871 common and 20,691,495 subordinated units and all of the equity interests in our general partner. We expect that our relationship with Natural Gas Partners will provide us with several significant benefits, including increased exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in midstream assets. Founded in 1988, Natural Gas Partners is among the oldest of the private equity firms that specialize in the energy industry. Through its family of eight institutionally-backed investment funds, Natural Gas Partners has sponsored over 100 portfolio companies and has controlled invested capital and additional commitments totaling $2.9 billion.
An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks described under Item 1A.
Item 1A. Risk Factors.
Industry Overview
The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its components to end-use markets, and consists of the gathering, compressing, treating, processing, transporting and selling of natural gas, and the transporting and selling of NGLs.
Natural Gas Demand and Production. Natural gas is a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to approximately 23.35 Tcf in 2010. The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the last three years, these sectors accounted for approximately 56% of the total natural gas consumed in the United States. In 2005, natural gas represented approximately 36% of all end-user domestic energy requirements. During the last three years, the United States has on average consumed approximately 22.3 Tcf per year, with average annual domestic production of approximately 18.5 Tcf during the same period. Driven by growth in natural gas demand and high natural gas prices, domestic natural gas production is projected to increase from 18.1 Tcf per year to 20.4 Tcf per year between 2005 and 2015.
Midstream Natural Gas Industry. Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. The process of natural gas gathering, processing, fractionation, storage and transportation ultimately results in natural gas and its components being delivered to end-users.
Natural Gas Gathering and Treating. The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once the well is completed, the well is connected to a gathering system.
Onshore gathering systems generally consist of a network of small diameter pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission.
Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations can be high in carbon dioxide or hydrogen sulfide. Natural gas with high carbon dioxide or hydrogen sulfide levels may cause significant damage to pipelines and is generally not acceptable to end-users. To alleviate the potential adverse effects of these contaminants, many pipelines regularly inject corrosion inhibitors into the gas stream.
Natural Gas Compression. Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Since wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production from the ground against a higher pressure that exists in the connecting gathering system. Natural gas compression is a mechanical process in which a volume of wellhead gas is compressed to a desired higher pressure, allowing gas flow into a higher pressure downstream pipeline to be brought to market. Field compression is typically used to lower the pressure of a gathering system to operate at a lower pressure or provide sufficient pressure to deliver gas into a higher pressure downstream pipeline. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced.
Natural Gas Processing. Natural gas is described as lean or rich depending on its content of heavy components or liquids content. These are relative terms, but as generally used, rich natural gas may contain as much as five to six gallons or more of NGLs per Mcf, whereas lean natural gas usually contains one to two gallons of NGLs per Mcf. NGLs have economic value and are utilized as a feedstock in the petrochemical and oil refining industries or directly as heating, engine or industrial fuels. Long-haul natural gas pipelines have specifications as to the maximum NGL content of the gas to be shipped. In order to meet quality standards for long-haul pipeline transportation, natural gas collected through a gathering system must be processed to separate hydrocarbon liquids that can have higher values as mixed NGLs from the natural gas.
The principal component of natural gas is methane, but most natural gas also contains varying amounts of NGLs including ethane, propane, normal butane, isobutane and natural gasoline. NGLs are typically recovered by cooling the natural gas until the mixed NGLs become separated through condensation. Cryogenic recovery methods are processes where this is accomplished at temperatures lower than −150o. These methods provide higher NGL recovery yields. After being extracted from natural gas, the mixed NGLs are typically transported via NGL pipelines or trucks to a fractionator for separation of the NGLs into their component parts.
In addition to NGLs, natural gas collected through a gathering system may also contain impurities, such as water, sulfur compounds, nitrogen or helium. As a result, a natural gas processing plant will typically provide ancillary services such as dehydration and condensate separation prior to processing. Dehydration removes water from the natural gas stream, which can form ice when combined with natural gas and cause corrosion when combined with carbon dioxide or hydrogen sulfide. Condensate separation involves the removal of hydrocarbons from the natural gas stream. Once the condensate has been removed, it may be stabilized for transportation away from the processing plant. Natural gas with a carbon dioxide or hydrogen sulfide content higher than permitted by pipeline quality standards requires treatment with chemicals called amines at a separate treatment plant prior to processing.
Natural Gas Fractionation. Fractionation is the process by which NGLs are further separated into individual, more valuable components. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline. Ethane is primarily used in the petrochemical industry to produce ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used in the production of ethylene and propylene and as a heating fuel, an engine fuel and an industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used in the production of ethylene, butadiene (a key ingredient in synthetic rubber), motor gasoline and isobutane. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily to produce motor gasoline and petrochemicals.
Fractionation takes advantage of the differing boiling points of the various NGL products. NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off the top of the tower where it is condensed and routed to storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated, and a different NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components. Because the fractionation process uses large quantities of heat, energy costs are a major component of the total cost of fractionation.
Natural Gas and NGL Transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the processed natural gas to industrial end-users and utilities and to other pipelines. NGLs are transported to market by means of pipelines, pressurized barges, rail car and tank trucks. The method of transportation utilized depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of NGLs being transported. Pipelines are generally the most cost-efficient mode of transportation when large, consistent volumes of NGLs are to be delivered.
Formation and Acquisitions
We are a Delaware limited partnership formed in March 2006, to own and operate the assets that have historically been owned and operated by Eagle Rock Holdings, L.P. and its subsidiaries. In 2002, certain members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In connection with the acquisition in 2003, of the Dry Trail plant, a CO2 tertiary recovery plant located in the Oklahoma panhandle, members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary midstream energy assets. Natural Gas Partners is one of the largest private equity fund sponsors of companies in the energy sector and, since 2003, has provided us with significant support in pursuing acquisitions.
Acquisition of Camp Ruby Gathering System and Indian Spring Processing Plant and Expansion of System
On July 28, 2004, we acquired certain minority-owned, non-operated undivided interests in natural gas gathering and processing assets from Black Stone Minerals for approximately $20.0 million. The assets consisted of a 20% undivided interest in the Camp Ruby gathering system and a 25% undivided interest in its related Indian Springs processing facility, both located in Southeast Texas. An affiliate of Enterprise Products Partners, L.P. currently owns the remaining interests in the facilities and is the operator of each of the facilities.
We began the construction of the Tyler County pipeline in September 2005. During the construction phase, we were able to secure large dedication areas from three additional producers in the vicinity of the Tyler County pipeline increasing our expected volumes from 15 MMcf/d to approximately an average of 30 MMcf/d. The Tyler County pipeline reached the first producer and began flowing natural gas on December 30, 2005. Construction of the pipeline was finished on February 28, 2006, at a cost of approximately $8.6 million. We are currently constructing an extension to the Tyler County pipeline which should be flowing gas by mid 2007. This line provides additional supply capacity and flexibility in addition to providing us the opportunity to take advantage of processing plant efficiencies for our customers, as well as a reduction in third-party processing fees.
Acquisition of Panhandle Assets
On December 1, 2005, we completed the purchase of ONEOK Texas Field Services, L.P., or ONEOK or predecessor, for approximately $528.0 million of cash. The assets acquired in the transaction consist of gathering and processing assets located in a ten county area in the Texas Panhandle and represent the majority of our assets in the Texas Panhandle.
In the first few months after the acquisition, we attracted 20 MMcf/d of new volumes at attractive processing margins. We are in the process of expanding our processing capacity in this area by beginning to refurbish and will restart an idle 20 MMcf/d processing plant, and by connecting the East Panhandle System with the West Panhandle System, where excess capacity currently exists. We also intend to expand our processing capacity by relocating and restarting a 24.5 MMcf/d facility in the latter part of 2007. In July, 2006, we began flowing gas across the 10-mile pipeline constructed to connect the gas in the east to the surplus plant capacity in the west.
Acquisition of Brookeland Assets
On March 31, 2006, we purchased an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line from Duke Energy Field Services, L.P. and on April 7, 2006, we purchased the remaining interest owned by Swift Energy Corporation in those same assets for an approximate total purchase price of $95.7 million. The acquired assets are located in southeast Texas and complement our existing southeast Texas assets. To motivate Swift Energy Corporation to enhance their drilling program, we have negotiated an incentive on all new well production. As such, they have resumed their drilling program.
We began the construction of a 16-mile extension to our Tyler County pipeline to reach the Brookeland processing plant, which as of April 30, 2006, operated with 72.2 MMcf/d of excess capacity. This extension will allow us to deliver the Tyler County pipeline volumes to our wholly-owned Brookeland processing facility which will enable us to avoid the processing fee we currently pay at the Indian Springs processing facility on these volumes. We also expect by delivering these volumes to our Brookeland processing facility we will achieve higher NGL recoveries as the Brookeland processing facility is more efficient than the Indian Springs processing facility.
Acquisition of MGS
In June 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P., which we refer to as MGS, for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline from a group of private investors, including Natural Gas Partners VII, L.P. We issued 798,155 of our common units (pre-IPO common units), which we refer to as the Deferred Common Units, to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. Prior to the acquisition, Natural Gas Partners VII, L.P. owned a 95% limited partnership interest in MGS and a 95% interest in its general partner, which owned a 1% general partner interest in MGS. We refer to the private investors who received common units in Eagle Rock Pipeline as partial consideration for the MGS acquisition as the June 2006 Private Investors. The March 2006 Private Investors and the June 2006 Private Investors are collectively referred to in the Annual Report as the “Private Investors.” Each of the Private Investors’ common units in Eagle Rock Pipeline was converted into common units in the Partnership upon consummation of our initial public offering on approximately a 1-for-0.719 common unit basis.
Our Assets
We own strategically positioned natural gas gathering and processing assets in two significant natural gas producing regions, the Texas Panhandle and the southeast Texas - western Louisiana region.
Texas Panhandle Operations
Our Texas Panhandle operations cover ten counties in Texas and one county in Oklahoma and consist of our East Panhandle System and our West Panhandle System. Through these systems, we offer producers a complete set of midstream wellhead-to-market services, including gathering, compressing, treating, processing, transporting and selling of natural gas and fractionating and transporting NGLs.
Our Texas Panhandle Systems are located in the Texas Railroad Commission, or the TRRC, District 10, which has experienced significant growth activity since 2002. According to the EIA, there were approximately
5.4 Tcf of total proved natural gas reserves at year-end 2006 in District 10. This area has experienced significant drilling activity during the last three years, and more than 550 new wells were completed in the counties served by our Texas Panhandle Systems during 2006.
Our Texas Panhandle Systems collectively include 3,509 miles of gathering pipeline, six active gas processing plants with an aggregate capacity of approximately 166 MMcf/d, and four inactive plants with an aggregate capacity of approximately 70 MMcf/d. Our Texas Panhandle Systems had an average throughput of 146 MMcf/d and an average NGL and condensate production of approximately 13,900 Bbls/d for the twelve months ended December 31, 2006.
East Panhandle System
The East Panhandle System gathers and processes natural gas produced in the Morrow and Granite Wash reservoirs of the Anadarko basin in Wheeler, Hemphill and Roberts Counties, an area in the eastern portion of the Texas Panhandle that has experienced substantial drilling and reserve growth since 2002.
The processing plants in our East Panhandle System are rapidly reaching capacity. In order to provide additional processing capacity to our East Panhandle System, we constructed in early 2006 a 10-mile pipeline from the West Panhandle System to the East Panhandle System, to activate inactive processing plants located in the West Panhandle System and relocate those processing plants in the East Panhandle System or connect the processing plants to existing pipeline connections, and to utilize unused capacity at existing processing plants.
System Description. The East Panhandle System consists of:
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approximately 773 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 35,289 horsepower of associated pipeline compression;
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three active natural gas processing plants with an aggregate capacity of 90 MMcf/d; and
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two natural gas treating facilities with an aggregate capacity of 75 MMcf/d.
The average throughput of the gathering system was approximately 93.4 MMcf/d for the twelve months ended December 31, 2006.
The Arrington processing plant is a refrigerated, lean oil absorption facility located in Hemphill County, Texas. The processing plant has seven compressors with an aggregate of approximately 6,000 horsepower and approximately 40 MMcf/d of processing capacity. During the twelve months ended December 31, 2006, the facility processed approximately 28.6 MMcf/d of natural gas and produced approximately 1,520 Bbls/d of NGLs. The Arrington processing plant was built in 1974.
The Canadian processing plant is a turbo expander cryogenic facility located in Hemphill County, Texas. The plant has eleven compressors with an aggregate of approximately 10,720 horsepower and approximately 25 MMcf/d of processing capacity. During the twelve months ended December 31, 2006, the facility processed approximately 36 MMcf/d of natural gas and produced approximately 2,300 Bbls/d of NGLs. As part of our Canadian processing plant, we own a 25 MMcf/d treating facility that removes carbon dioxide and small amounts of hydrogen sulfide from the natural gas. The Canadian processing plant was built in 1977.
Our Goad treating facility is a 50 MMcf/d treating facility that removes carbon dioxide and hydrogen sulfide from the natural gas.
In addition, we purchased Midstream Gas Services, L.P. in June 2006, which consists of facilities located in Roberts County within our East Panhandle System. The facilities consist of approximately four miles of natural gas gathering pipelines with associated pipeline compression and an active natural gas processing plant with aggregate capacity of 25 MMcf/d. The processing plant was constructed in late 2005 and early 2006, and was successfully started in the second quarter of 2006. The plant is currently processing approximately 3 MMcf/d of natural gas. This facility is connected to our East Panhandle System, allowing additional natural gas supply from nearby Hemphill County to be processed through this facility. The residue gas is currently being delivered to the ANR pipeline.
Natural Gas Supply. As of December 31, 2006, 592 wells and central delivery points were connected to our East Panhandle System. There are approximately 73 producers with the primary producers connected to the East Panhandle System being Devon Energy Production Company, L.P., Peak Operating of Texas LLC, Prize Operating Company and ChevronTexaco Exploration & Production. The Anadarko basin, from where this gas is produced, extends from the western portion of the Texas Panhandle through most of central Oklahoma.
Natural gas production from wells located within the area served by the East Panhandle System generally has steep rates of decline during the first few years of production. Approximately 64% of the natural gas that is gathered on our East Panhandle System is processed to recover the NGL content, which generally ranges from 4.0 to 5.0 gpm for this processed natural gas. Approximately 36% of the natural gas gathered in the East Panhandle System is not processed but is treated for removal of carbon dioxide and hydrogen sulfide to make the natural gas marketable. This natural gas can be isolated and sent to the treating facilities while the remaining system is used to gather the natural gas into the processing plants.
The East Panhandle System is located in an area characterized by significant growth in drilling activity and production. In 2006, approximately 744 wells have been permitted and 472 wells have been drilled in the area. On the East Panhandle System, natural gas is purchased at the wellhead primarily under percent-of-proceeds and fee-based arrangements that primarily range from one to five years in term. As of December 31, 2006, approximately 77%, 22% and 1% of our total throughput in the East Panhandle System was under percent-of-proceeds, fee-based and keep-whole arrangements, respectively. For a more complete discussion of our natural gas purchase contracts, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Operations.
Markets. We marketed the residue natural gas and the NGLs on the East Panhandle System to approximately six purchasers. Interconnects exist with Northern Natural Gas Co. at the Canadian processing plant and Southern Star Central Gas Pipeline, Inc.
Pursuant to an exchange agreement, the NGLs from our East Panhandle System are currently transported to the ONEOK NGL pipeline at Mont Belvieu, Texas or Conway, Kansas, where the NGLs are being marketed by ONEOK. During 2006, we began marketing these NGLs, which we believe enhanced the netback to us and the producers because of better market pricing and improved marketing fee arrangements. With the December 2005 Panhandle acquisition, a significant portion of the residue natural gas and NGLs were purchased by ONEOK Energy Services in the first half of 2006. The exchange agreement with ONEOK Energy Services expired on May 31, 2006.
The condensate from the East Panhandle System is transported by truck to central tank facilities and injected for sale into the ConocoPhillips Y-2 system.
Competition. Our primary competitor in this area is Enbridge, Inc.
West Panhandle System
The West Panhandle System gathers and processes natural gas produced from the Anadarko basin in Moore, Potter, Hutchinson, Carson, Roberts, Gray, Wheeler and Collingsworth Counties located in the western part of the Texas Panhandle.
System Description. The West Panhandle System consists of:
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approximately 2,736 miles of natural gas gathering pipelines, ranging from two inches to 12 inches in diameter, with 81,473 horsepower of associated pipeline compression;
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four active natural gas processing plants with an aggregate capacity of 101 MMcf/d;
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three natural gas treating facilities with an aggregate capacity of 65 MMcf/d;
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a propane fractionation facility with capacity of 1,000 Bbls/d; and
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a condensate collection facility.
The average throughput of the gathering system was approximately 50.8 MMcf/d for the twelve months ended December 31, 2006.
The Cargray processing plant is a turbo expander cryogenic facility located in Carson County, Texas. The plant has seven compressors with an aggregate of approximately 7,000 horsepower and approximately 30 MMcf/d of processing capacity. In addition to the cryogenic plant, the processing facility also includes a 30 MMcf/d dehydration unit, a 12 MMcf/d deoxygenation unit and a 1,000 Bbls/d propane fractionator, which also includes a deethanizer, a depropanizer, 136,000 gallons of storage capacity, loading pumps and a truck loading rack. During the twelve months ended December 31, 2006, the facility processed approximately 14 MMcf/d of natural gas and produced approximately 2,400 Bbls/d of NGLs. In addition, approximately 3.6 MMcf/d of the natural gas gathered by the Cargray plant is treated for the removal of hydrogen sulfide and carbon dioxide at the Shaefer treating facility in Carson County, Texas. The Cargray plant was built in 1974.
The Gray processing plant is a turbo expander cryogenic facility located in Gray County, Texas. The plant has seven compressors with an aggregate of approximately 2,000 horsepower and approximately 20 MMcf/d of processing capacity. During the twelve months ended December 31, 2006, the facility processed approximately 14.4 MMcf/d of natural gas and produced approximately 1,940 Bbls/d of NGLs. This plant includes an inactive 12 gpm treating facility and a 20 MMcf/d dehydration unit. The Gray plant was built in 1984.
The condensate collection facility, which is located near the Gray processing plant, serves as a central collection point for the condensate produced on the West Panhandle System. The facility includes several horizontal feed tanks, a 1,500 Bbls/d condensate stabilizer, horizontal make tanks, truck loading and unloading facilities and a pipeline connection to ConocoPhillips. Condensate is transported by a pipeline from the Gray processing plant and by truck from other parts of the West Panhandle System.
The Lefors processing plant is a cryogenic processing facility located in Gray County, Texas. The plant has an aggregate of 1,225 horsepower of inlet compression and 400 horsepower of refrigeration compression and approximately 11 MMcf/d of processing capacity. The processing facility also includes a 5 gpm amine product treater. During the twelve months ended December 31, 2006, the facility processed approximately 7.6 MMcf/d of natural gas and produced approximately 1,700 Bbls/d of NGLs. The Lefors plant was originally constructed in 1928, converted in 1970 and was replaced in 1995.
The Stinnett processing plant is a turbo expander cryogenic facility located in Moore County, Texas. The plant has five compressors with an aggregate of approximately 6,300 horsepower and approximately 40 MMcf/d of processing capacity. The processing facility also includes a 14 gpm treating facility, a 40 MMcf/d dehydration unit, a 40 MMcf/d dehydrator and a condensate stabilizer. During the twelve months ended December 31, 2006, the facility processed approximately 14.1 MMcf/d of natural gas and produced approximately 1,550 Bbls/d of NGLs. The Stinnett plant was built in 1984.
We believe we have opportunities to increase the profitability of the West Panhandle System primarily by utilizing excess processing capacity on this system to process natural gas transported from our East Panhandle System as well as by rationalizing assets, reducing fuel expense and other operating costs and improving NGL recovery efficiency. Additionally, opportunities exist to capture additional natural gas production associated with the re-completion of existing wells that were not developed using advanced technology and infill drilling.
Natural Gas Supply. As of December 31, 2006, 1,737 wells and central delivery points were connected to the West Panhandle System. There are 195 producers connected to the West Panhandle System with Chesapeake, Excel Energy, Chevron, XTO Energy, Questa Energy Corporation, and James Reneau Seed Corp. being the primary producers.
Wells located in the West Panhandle System produce natural gas associated with the crude oil production from the wells. These wells generally have long production lives with predictable production base decline rates of approximately 6% per year. These wells generally produce natural gas having an NGL content of between 6.5 and 13.0 gpm, a level that is considered extremely high in comparison to average levels of NGL content of between 1.0 and 2.0 gpm related to natural gas production that is not associated with crude oil production.
Significant compression horsepower and significantly more pipeline capacity are required to move this natural gas to the processing facilities because of the high NGL content. Because of the complex level of service and high quality of the natural gas, the value of the natural gas produced and the margins associated with our services are typically higher for the West Panhandle System as compared to the East Panhandle System.
The West Panhandle System is located in a mature drilling area that produces high NGL content natural gas. New drilling activity around the West Panhandle System has been less active over the past several years. However, producers are continually re-working their existing properties to maintain productive reserves, which has resulted in a low natural gas production decline rate.
On the West Panhandle System, 40% of the natural gas is purchased at the wellhead primarily under keep-whole arrangements with a $3.0 million per year gathering demand fee. The remaining 60% of the natural gas purchased is primarily under percent-of-proceeds contracts. The natural gas from this system is dedicated under long-term contracts. For a more complete discussion of our natural gas purchase contracts, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Operations.
Markets. Our primary purchaser of the residue gas and NGLs on the West Panhandle System for 2005 was ONEOK Energy Services, which represented approximately 80% of revenues on the system for the twelve months ended December 31, 2006. Our exchange with ONEOK Energy Services ended May 31, 2006, and we have expanded our purchasers, including ONEOK Energy Services, to six portfolios of marketing outlets. In addition, condensate produced on the system is trucked and purchased by SemCrude, L.P. and Petro Source Partners, LP.
Competition. Our primary competition in this area is Duke Energy Field Services, L.P.
Southeast Texas and Louisiana Operations
Our southeast Texas and Louisiana operations are located primarily in Polk, Tyler, Jasper and Newton Counties, Texas and Vernon Parish, Louisiana. Through our southeast Texas and Louisiana System, we offer producers natural gas gathering, treating, processing and transportation and NGL transportation.
Systems Description. The facilities that comprise our southeast Texas and Louisiana operations consist of:
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approximately 1,049 miles of natural gas gathering pipelines, ranging from four inches to 12 inches in diameter, with 5,200 horsepower of associated pipeline compression;
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a 100 MMcf/d cryogenic processing plant;
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a 150 MMcf/d cryogenic processing plant, in which we own a 25% undivided interest; and
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a 19-mile NGL pipeline.
The Brookeland System is located in Jasper and Newton Counties, Texas and consists of approximately 650 miles of natural gas gathering pipelines, ranging from 4 inches to 12 inches in diameter, and the Brookeland processing plant. The gathering system has capacity of approximately 120 MMcf/d. The gathering system utilizes approximately 1,100 horsepower to gather the natural gas from 156 wells and central delivery points. This system was acquired in second quarter 2006.
The Masters Creek System is located in Vernon, Beauregard and Rapides Parishes, Louisiana and consists of approximately 250 miles of natural gas gathering pipelines, ranging from two inches to 16 inches in diameter. The gathering system has capacity of approximately 200 MMcf/d. The gathering system utilizes approximately 4,000 horsepower to gather natural gas from 52 wells and central delivery points. This system was acquired in second quarter 2006.
The Brookeland processing plant is a cryogenic natural gas processing and treating facility located in Jasper County, Texas. The plant processes the gas delivered from the Brookeland and Masters Creek systems. The plant has processing capacity of approximately 100 MMcf/d. This system was acquired in second quarter
2006. For the period since the Partnership acquired the facilities, approximately 27.1 MMcf/d of natural gas was processed for 2006 and produced approximately 1,900 Bbls/d of NGLs.
The Camp Ruby System is located in Polk, Hardin and Tyler Counties, Texas and consists of approximately 126 miles of natural gas gathering pipelines, ranging from two inches to eight inches in diameter, and the Indian Springs processing plant. The gathering system average throughput was approximately 71 MMcf/d for December 2006. The system delivers all of the natural gas to the Indian Springs processing plant. We own a 20% undivided interest in the Camp Ruby System and a subsidiary of Enterprise Products Partners, L.P., owns the remaining 80% and operates the system.
The Indian Springs processing plant is a cryogenic natural gas processing and treating plant located in Polk County, Texas. The Indian Springs processing plant is comprised of two cryogenic plants with total operational capacity of 150 MMcf/d. During December 2006, the facility processed approximately 100 MMcf/d of natural gas and produced approximately 6,900 Bbls/d of NGLs. We own a 25% undivided interest in the Indian Springs processing plant and a subsidiary of Enterprise Products Partners, L.P., owns the remaining 75% and operates the facility.
On February 28, 2006, we completed construction on our Tyler County pipeline, a 23-mile, 10-inch diameter natural gas pipeline that is the first segment of a natural gas gathering system that crosses Tyler County, Texas. As of December 2006, the Tyler County gathering system had a capacity of 60 MMcf/d, with an average throughput of approximately 28.4 MMcf/d. Construction of an extension of the Tyler County gathering system to the Brookeland System is expected to be in service by the end of the first half of 2007, at a cost of approximately $16.0 million, which will increase capacity of the existing pipeline to 45 MMcf/d and allows existing gas on the Tyler County Pipeline to be processed at the Brookeland processing plant which is owned 100% by us.
The Jasper NGL pipeline is a 19-mile, 6-inch diameter pipeline that is located in Jasper and Newton Counties, Texas. The pipeline capacity is 18 MBbl/d and delivers NGLs from the Brookeland plant to the Black Lake Pipeline which is jointly owned by Duke Energy Field Services, L.P. and BP America Production Company, for ultimate delivery of the NGLs to a fractionation plant located in Mont Belvieu, Texas.
The Live Oak gathering system is located in Live Oak County, Texas. It gathers gas from Zinergy and redelivers it to the nearby Copano pipeline system for a fixed fee. This system was built and put in service in November 2005. Zinergy had drilled and completed three wells on this system by December 2006. Volumes were averaging 3.4 MMcf/d as of December 2006.
Natural Gas Supply. As of December 31, 2006, approximately 209 wells and central delivery points were connected to our systems in the southeast Texas and Louisiana regions. Our southeast Texas and Louisiana operations are located in an area experiencing an increase in drilling activity and production. The Texas Railroad Commission and the Louisiana Department of Natural Resources have issued 179 drilling permits in Tyler, Polk, Jasper and Newton Counties, Texas and Vernon, Beauregard and Rapides Parish, Louisiana from January 2006 through December 2006. We have secured areas of dedication from Ergon Exploration Inc. (“Ergon”), Black Stone Minerals Co., Delta Petroleum Corp., B.W.O.C. Inc. (“B.W.O.C.”) and Pogo Producing Company. Each of the entities has at least five additional locations identified as drilling locations on this acreage. The Ergon and B.W.O.C. gas was connected to our Tyler County pipeline in March 2006. As of December 31, 2006, the gas on the Tyler County pipeline was producing at a combined rate of approximately 28.4 MMcf/d.
The natural gas supplied to us under our southeast Texas and Louisiana System is generally dedicated to us under individually negotiated long-term and life of lease contracts. Contracts associated with this production are generally percent-of-proceeds and percent-of-liquids arrangements. Natural gas is purchased at the wellhead from the producers under percent-of-proceeds contracts or keep-whole contracts or is gathered for a fee and redelivered at the plant tailgates. For a more complete discussion of our natural gas purchase contracts, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Operations.
Markets. Residue gas remaining after processing is primarily taken in kind by the producer customers into the markets available at the tailgates of the plants. Some of the available markets are Houston Pipeline Company, Natural Gas Pipeline Company and Tennessee Gas Pipeline. Our NGLs are sold to Duke Energy Field Services, L.P. and our condensate production is sold to SemCrude, L.P.
Competition. Our primary competition in this area includes Anadarko Petroleum and Enterprise Products Partners, L.P.
Safety and Maintenance Regulation
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act of 1970, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection and auditing designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety. Our east Texas and Louisiana assets have not experienced a lost-time accident since June 2005. Our Texas Panhandle assets have not experienced a lost-time accident since early 2004. Since our inception, we have not experienced a lost-time accident.
Regulation of Operations
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation.
Our Camp Ruby gathering system does provide limited interstate transportation services pursuant to Section 311 of the Natural Gas Policy Act (“Section 311”). The rates, terms and conditions of such transportation service are subject to FERC jurisdiction. Under Section 311, intrastate pipelines providing interstate service may avoid jurisdiction that would otherwise apply under the Natural Gas Act. Section 311 regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Additionally, the terms and conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval. Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service
established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal Natural Gas Act jurisdiction by FERC and/or the imposition of administrative, civil and criminal penalties.
Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating gathering facilities in Louisiana, and has authority to review and authorize the construction, acquisition, abandonment and interconnection of physical pipeline facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities.
The majority of our gathering systems in Texas have been deemed non-utilities by the TRRC. Under Texas law, non-utilities are not subject to rate regulation by the TRRC. Should the status of these non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers. Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The “rural gathering exemption” under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute, including those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption,” however, may be restricted in the future. With respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation, or DOT, have passed or are considering heightened pipeline safety requirements. We operate our facilities in full compliance with local, state and federal regulations, including DOT 192 and 195.
Eleven miles of our Turkey Creek gathering system is regulated as a utility by the TRRC. To date, there has been no adverse affect to our system due to this regulation. In addition, the four miles of gathering system that we recently purchased from MGS is regulated by the TRRC.
Our purchasing and gathering operations are subject to ratable take and common purchaser statutes. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Texas and Louisiana have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and
implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differently than other natural gas marketers with whom we compete.
Intrastate NGL Pipeline Regulation. We do not own any NGL pipelines subject to FERC’s regulation. We do own and operate an intrastate common carrier NGL pipeline subject to the regulation of the TRRC. The TRRC requires that intrastate NGL pipelines file tariff publications that contain all the rules and regulations governing the rates and charges for service performed. The applicable Texas statutes require that NGL pipeline rates provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of NGL pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although we cannot assure that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
Environmental Matters
We operate pipelines, plants, and other facilities for gathering, compressing, treating, processing, fractionating, or transporting natural gas, NGLs, and other products that are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair our operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. The costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting our activities.
The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, accidental releases or spills are associated with our operations, and we cannot assure that we will not incur significant costs and liabilities as a result of such releases or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the release of hazardous substances into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA.
We also may incur liability under the Resource Conservation and Recovery Act, as amended, also known as “RCRA,” which imposes requirements related to the handling and disposal of solid and hazardous wastes. While there exists an exclusion from the definition of hazardous wastes for certain materials generated in the exploration, development, or production of crude oil and natural gas, in the course of our operations we may generate petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous wastes.
We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination. We intend to conduct environmental investigations at 11 properties, the aggregate cost of which is estimated to range between $0.2 million and $0.4 million and for which we have accrued reserves in the amount of $0.3 million as of December 31, 2006. Depending on the findings made during these investigations, and in anticipation of implementing amended SPCC plans at multiple locations as well as performing selected cavern closures, we estimate that an additional $1.2 million to $2.5 million in costs could be incurred in resolving environmental issues at those properties. Separately, (1) we are entitled to indemnification with respect to certain environmental liabilities retained by prior owners of these properties, and (2) we purchased an environmental pollution liability insurance policy.
The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, we do not believe that such requirements will have a material adverse affect on our operations.
The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of stormwater in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater and stormwater and develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. The EPA issued revised SPCC rules in July 2002 whereby SPCC plans are subject to more rigorous review and certification procedures. Pursuant to these revised rules, SPCC plans must be amended, if necessary to assure compliance, and implemented by no later than October 31, 2007. We believe that our operations are in substantial compliance with applicable Clean Water Act and analogous state requirements, including those relating to wastewater and stormwater discharges and SPCC plans.
Title to Properties and Rights-of-Way
Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and
other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
Employees
To carry out our operations, Eagle Rock Energy G&P, LLC, the general partner of our general partner, employs approximately 163 people who provide direct support for our operations. None of these employees are covered by collective bargaining agreements.
Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently a party to any material litigation.
We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Available Information
We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”), under the Securities Exchange Act of 1934 (the “Exchange Act”). Materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549, may be read and copied. Additional information about the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.
We also make available free of charge on or through our Internet website (http://www.eaglerockenergy.com) or through our Investor Relations group (281-408-1200), our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Item 1A.
Risk Factors.
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units and the trading price of our common units could decline.
Risks Related to Our Business
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of supplies of natural gas and NGLs, which are dependent on certain factors beyond our control. Any decrease in supplies of natural gas or NGLs could adversely affect our business and operating results.
Our gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies of natural gas. The primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (1) the level of successful drilling activity by producers near our systems and (2) our ability to compete for volumes from successful new wells.
The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. Currently, natural gas prices are high in relation to historical prices. For example, the rolling twelve-month average NYMEX daily settlement price of natural gas has increased from $5.49 per MMBtu as of December 31, 2003 to $7.23 per MMBtu as of December 31, 2006. If the high price for natural gas were to decline, the level of drilling activity could decrease. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering and pipeline transportation systems and our natural gas treating and processing plants, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, the ability of producers to obtain necessary drilling and other governmental permits, and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.
Natural gas, NGLs and other commodity prices are volatile, and a reduction in these prices could adversely affect our cash flow and our ability to make distributions.
We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in 2006 ranged from a high of $9.87 per MMBtu to a low of $3.63 per MMBtu. The NYMEX daily settlement price for crude oil for the prompt month contract in 2006 ranged from a high of $77.03 per barrel to a low of $55.81 per barrel. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:
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the impact of weather on the demand for oil and natural gas;
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the level of domestic oil and natural gas production;
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the availability of imported oil and natural gas;
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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate transportation systems;
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the availability and marketing of competitive fuels;
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the impact of energy conservation efforts; and
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the extent of governmental regulation and taxation.
Our natural gas gathering and processing businesses operate under two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality gas and NGLs or NGL products resulting from our processing activities. Under keep-whole arrangements, we receive the NGLs removed from the natural gas during our processing operations as the fee for providing our services in exchange for replacing the thermal content removed as NGLs with a like thermal content in pipeline-quality gas or its cash equivalent. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, under keep-whole arrangements it is more profitable for us to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants. For a detailed discussion of these arrangements, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Our Operations.
Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.
We are exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related largely to the effectiveness and scope of our hedging activities. In order to reduce our exposure to commodity price risk, we directly hedged substantially all of our share of expected NGL volumes in 2006 and 2007 under percent-of-proceed and keep-whole contracts. This has been accomplished primarily through the purchase of NGL put contracts but also through executing NGL costless collar contracts and swap contracts. We have also hedged substantially all of our share of expected NGL volumes from 2008 through 2010 under percent-of-proceed contracts through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to cover our short natural gas position. For periods after 2010, our management will evaluate whether to enter into any new hedging arrangements, but there can be no assurance that we will enter into any new hedging arrangement or that our future hedging arrangements will be on terms similar to our existing hedging arrangements.
To the extent we hedge our commodity price and interest rate risk, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. Furthermore, because we have entered into derivative transactions related to only a portion of the volume of our expected natural gas supply and production of NGLs and condensate from our processing plants, we will continue to have direct commodity price risk to the unhedged portion. Our actual future supply and production may be significantly higher or lower than we estimate at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimate, we will have less commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the underlying physical commodity, resulting in a reduction of our liquidity.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or
ineffective, or our hedging policies and procedures are not properly followed or do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
As a result of our hedging activities and our practice of marking to market the value of our hedging instruments, we will also experience significant variations in our unrealized derivative gains/(losses) from period to period. These variations from period to period will follow variations in the underlying commodity prices and interest rates. As this item is of a non-cash nature, it will not impact our cash flows or our ability to make our distributions. However, it will impact our earnings and other profitability measures. To illustrate, during the twelve months ended December 31, 2006, we experienced positive movements in our underlying commodities’ prices which led to an unrealized derivative loss of $26.3 million. This $26.3 million loss had a direct impact on our net income (loss) line resulting in a net loss of $23.1 million. For additional information regarding our hedging activities, please read Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering and pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.
We typically do not obtain independent evaluations of natural gas reserves connected to our systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions.
We depend on certain natural gas producer customers for a significant portion of our supply of natural gas. The loss of any of these customers could result in a decline in our volumes, revenues and cash available for distribution.
We rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. Our two largest suppliers for the year ended December 31, 2005, affiliates of Chesapeake Energy Corporation and Devon Energy Corporation, accounted for approximately 19% and 9%, respectively, of our 2005 natural gas supply. The make-up of gas suppliers can change from time to time based upon a number of reasons, some of which are success of the producer’s drilling programs, additions or cancellations of new agreements, and acquisition of new systems. As of December 31, 2006, our two largest suppliers were affiliates of Chesapeake Energy Corporation and Prize Operating Company, accounting for approximately 12% and 10% respectively, of our natural gas supply. We may be unable to negotiate long-term contracts or extensions or replacements of existing contracts, on favorable terms, if at all. The loss of all or even a portion of the natural gas volumes supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition, unless we were able to acquire comparable volumes from other sources.
We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.
If third-party pipelines and other facilities interconnected to our systems become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil and natural gas companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Likewise, our customers who produce NGLs may develop their own processing facilities in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Our natural gas gathering and intrastate transportation operations are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, except for Section 311 as discussed below, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, FERC may not continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC and the courts.
Other state and local regulations also affect our business. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our proprietary gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge proprietary
status of a line, or the rates, terms and conditions of a gathering line providing transportation service. Please read Item 1. Business - Regulation of Operations.
We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, also known as the “EPA,” and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.
There is inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to our handling of petroleum hydrocarbons and wastes, air emissions and water discharges related to our operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred under these environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover some or any of these costs from insurance. See Item 1. Business - Environmental Matters.
Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas
supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.
Any acquisition involves potential risks, including, among other things:
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mistaken assumptions about volumes, revenues and costs, including synergies;
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an inability to integrate successfully the businesses we acquire;
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inadequate expertise for new geographic areas, operations or products and services;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of management’s and employees’ attention from other business concerns;
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unforeseen difficulties operating in new product areas or new geographic areas;
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customer or key employee losses at the acquired businesses; and
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establishment of internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and the limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.
Our operations are subject to many hazards inherent in the gathering, compressing, treating, processing and transporting of natural gas and NGLs, including:
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damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
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fires and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
In December 2005, we entered into up to a $475.0 million senior secured credit facility, consisting of up to a $400.0 million term loan facility and up to a $75.0 million revolving credit facility for our acquisition of the ONEOK Texas natural gas gathering and processing assets. The revolver facility was increased to $100.0 million in June 2006. On August 31, 2006, we entered into an amended and restated credit facility that provides for an aggregate of approximately $500.0 million borrowing capacity, of which we have the ability to incur up to $80.0 million of additional debt, subject to limitations in our credit facility. Our level of debt could have important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
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we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders;
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our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our debt level may limit our flexibility in responding to changing business and economic conditions.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our amended and restated credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.
Restrictions in our amended and restated credit facility limit our ability to make distributions and limit our ability to capitalize on acquisitions and other business opportunities.
Our amended and restated credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our amended and restated credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions.
Increases in interest rates, which have recently experienced record lows, could adversely impact our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
The credit markets recently have experienced record lows in interest rates over the past several years. As the overall economy strengthens, it is likely that monetary policy will continue to tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
Due to our lack of industry and geographic diversification, adverse developments in our midstream operations or operating areas would reduce our ability to make distributions to our unitholders.
We rely on the revenues generated from our midstream energy businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and condensate. Furthermore, all of our assets are located in the Texas Panhandle, southeast Texas and Louisiana. Due to our lack of diversification in industry type and location, an adverse development in one of these businesses or operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
We are exposed to the credit risks of our key producer customers, and any material nonpayment or nonperformance by our key producer customers could reduce our ability to make distributions to our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our producer customers. Any material nonpayment or nonperformance by our key producer customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers may be highly leveraged and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud.
Prior to our initial public offering, which was completed on October 24, 2006, we have been a private company and have not filed reports with the SEC. We produce our consolidated financial statements in accordance with the requirements of GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, annually to review and report on, and our independent registered public accounting firm to attest to, our internal control over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2007. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
Risks Inherent in an Investment in Us
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.
In order to make our cash distributions at our initial distribution rate of $0.3625 per common unit per complete quarter, or $1.45 per unit per year, we will require available cash of approximately $15.3 million per quarter, or $61.2 million per year, based on the common units and subordinated units outstanding as of the date of this report. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the fees we charge and the margins we realize for our services;
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the prices of, level of production of, and demand for, natural gas, NGLs and condensate;
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the volume of natural gas we gather, treat, compress, process, transport and sell, and the volume of NGLs we transport and sell;
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the producers’ drilling activities and success of such programs;
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the level of competition from other midstream energy companies;
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the level of our operating and maintenance and general and administrative costs;
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the relationship between natural gas and NGL prices; and
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prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
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the level of capital expenditures we make;
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the cost of acquisitions;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets;
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restrictions contained in our debt agreements; and
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the amount of cash reserves established by our general partner.
The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
The amount of available cash we need to pay the minimum quarterly distribution for four quarters on our common units is $30.0 million and $1.2 million as a full distribution on our general partner units and a full distribution on our subordinated units is $30.0 million, totaling $61.2 million. The amount of our pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended December 31, 2006 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common units and subordinated units for those periods; however, it would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units. For the February 15, 2007, cash distribution, the common units received their full distribution for the December 2006 quarter on an adjusted basis to reflect the timing on the initial public offering. No distributions were made to the general partner or subordinated units for the period.
We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy.
Eagle Rock Holdings, L.P., owns a 54.0% limited partner interest in us and will control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has conflicts of interest, which may permit it to favor its own interests.
Eagle Rock Holdings, L.P, owns and controls our general partner. Holdings is owned and controlled by the NGP Investors. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners, the NGP Investors. Conflicts of interest may arise
between the NGP Investors and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
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neither our partnership agreement nor any other agreement requires the NGP Investors to pursue a business strategy that favors us;
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our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest;
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The NGP Investors and its affiliates are not limited in their ability to compete with us;
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our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
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our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;
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our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;
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our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
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our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;
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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
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our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.
Affiliates of our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, affiliates of our general partner may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets.
Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.
Prior to making distribution on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support
services to us, and there is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended and restated credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units.
Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise free of fiduciary duties to us and our unitholders, including determining how to allocate corporate opportunities among us and our affiliates. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:
•
its limited call right;
•
its voting rights with respect to the units it owns;
•
its registration rights; and
•
and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
Our partnership agreement restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
•
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;
•
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of this standard requires that our general partner must believe that the decision is in the best interests of our partnership;
•
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
•
provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is:
•
approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;
•
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of Eagle Rock Energy G&P, LLC, the general partner of our general partner, has been and will be
chosen by the members of Eagle Rock Energy G&P, LLC. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Our general partner and its affiliates own 55.1% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period (which in general is expected to end in late 2009, unless we distribute at least $2.175 for the period ending September 30, 2007) and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or Eagle Rock Energy G&P, LLC, from transferring all or a portion of their respective ownership interest in our general partner or Eagle Rock Energy G&P, LLC to a third party. The new owners of our general partner or Eagle Rock Energy G&P, LLC would then be in a position to replace the board of directors and officers of Eagle Rock Energy G&P, LLC with its own choices and thereby influence the decisions taken by the board of directors and officers.
We may issue additional units without limited partner approval, which would dilute ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
•
our unitholders’ proportionate ownership interest in us will decrease;
•
the amount of cash available for distribution on each unit may decrease;
•
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
•
the ratio of taxable income to distributions may increase;
•
the relative voting strength of each previously outstanding unit may be diminished; and
•
the market price of the common units may decline.
Affiliates of our general partner, certain private investors, and employees, may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
Management of Eagle Rock Energy G&P, LLC, the general partner of our general partner and the NGP Investors and their affiliates (both through their interests in Eagle Rock Holdings), certain private investors, including the selling unitholders, and certain employees of Eagle Rock Energy G&P, LLC hold an aggregate of 6,851,960 common units, including 122,450 common units which are subject to an overall three-year vesting requirement, and 20,691,495 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop. In addition, we have entered into a registration rights agreement with Eagle Rock Holdings, which requires us to file with the SEC a registration statement within 90 days of our receipt of a request from Eagle Rock Holdings to file a registration statement and to have such registration statement become effective within 180 days of receipt of such request. Following the effective date of the registration statement and the expiration of any lock-up agreements applicable to the selling unitholders and Eagle Rock Holding, these holders may sell their common units into the public markets.
Our general partner has a limited call right that may require limited partners to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, the limited partners may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Limited partners may also incur a tax liability upon a sale of units. Our general partner and its affiliates will own approximately 10.5% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 55.1% of our outstanding common units.
Liability of a limited partner may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Limited partners could be liable for any and all of our obligations as a general partner if:
•
a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
•
the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
The price of our common units may fluctuate significantly.
Prior to October 24, 2006, there was no public market for the common units. The lack of a liquid market in our common units may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including:
•
our quarterly distributions;
•
our quarterly or annual earnings or those of other companies in our industry;
•
loss of a large customer;
•
announcements by us or our competitors of significant contracts or acquisitions;
•
changes in accounting standards, policies, guidance, interpretations or principles;
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general economic conditions;
•
the failure of securities analysts to cover our common units or changes in financial estimates by analysts;
•
future sales of our common units; and
•
other factors described in these “Risk Factors.”
We will incur increased costs as a result of being a publicly traded partnership.
We have little history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the NASDAQ Global Market, have required changes in corporate governance practices of publicly traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included approximately $2.5 million of estimated incremental costs per year associated with being a publicly traded
partnership for purposes of our financial forecast range; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
Tax Risks to Common Unitholders
The tax efficiency of our partnership structure depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We will, for example, be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending December 31, 2007. Specifically, the Texas tax will be imposed at a maximum effective rate of 1.0% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Limited partners may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, limited partners will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were received from us. Limited partners may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If a limited partner sells common units, the limited partner will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Prior distributions to a limited partner in excess of the total net taxable income allocated for a common unit, which decreased the limited partner’s tax basis in that common unit, will, in effect, become taxable income to the limited partner if the common unit is sold at a price greater than their tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if a limited partner sells units, the limited partner may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If a limited partner is a tax-exempt entity or a foreign person, the limited partner should consult a tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the limited partners. It also could affect the timing of these tax benefits or the amount of gain from sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our limited partners.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
Limited partners will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.
In addition to federal income taxes, a limited partner will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the limited partner does not live in any of those jurisdictions. A limited partner will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, a limited partner may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in the States of Louisiana, Texas and Oklahoma. Each of these states, other than Texas, currently imposes a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is a limited partner’s
responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.
Item 1B.
Item 1B.
Unresolved Staff Comments.
This item is not applicable to us.
Item 2.
Item 2.
Properties.
A description of our properties is contained in Item 1. Business of this Annual Report. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have been subordinated to the rights-of-way grants. We have obtained, where necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county or parish roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.
Some of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.
We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties nor will they materially interfere with their use in the operation or our business.
Item 3.
Item 3.
Legal Proceedings.
We and our subsidiaries may become party to legal proceedings which arise from time to time in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on the financial statements.
We carry insurance with coverage and coverage limits consistent with our assessment of risks in our business and of an acceptable level of financial exposure. Although there can be no assurance such insurance will be sufficient to mitigate all damages, claims or contingencies, we believe our insurance provides reasonable coverage for known asserted or unasserted claims. In the event we sustain a loss from a claim and the insurance carrier disputed coverage or coverage limits, we may record a charge in a different period than the recovery, if any, from the insurance carrier.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our common units have been listed on the NASDAQ Global Market under the symbol “EROC.” The following table sets forth the high and low sales prices of our common units as reported by the NASDAQ Global Market, as well as the amount of cash distributions paid per quarter from our initial public offering date, October 24, 2006, through December 31, 2006.
(1)
Represents a prorated distribution to the common unitholders from the IPO date of October 24, 2006 through December 31, 2006.
(2)
Approved by the Board of the Partnership on January 24, 2007.
We have also issued 20,691,495 subordinated units, for which there is no established market. There is one holder of record of our subordinated units as of the date of this report.
The last reported sale price of our common units on the NASDAQ Global Market on March 30, 2007, was $20.36. As of that date, there were 21 holders of record and approximately 8,000 beneficial owners of our common units.
Cash Distribution Policy
We will distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:
•
provide for the proper conduct of our business;
•
comply with applicable law or any partnership debt instrument or other agreement; or
•
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.
In addition to distributions on its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.4169 per unit, 25% of the amounts we distribute in excess of $0.4531 per unit and 50% of amounts we distribute in excess of $0.5438 per unit.
Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Amended and Restated Credit Agreement.
Sales of Unregistered Securities
On May 25, 2006, in connection with the formation of Eagle Rock Energy Partners, L.P. (the “Partnership”), the Partnership issued to (i) its general partner the 2% general partner interest in the Partnership for $20 and (ii) Eagle Rock Holdings, L.P., the 98% limited partner interest in the Partnership for $980. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.
On March 27, 2006, certain private investors contributed $98.3 million to Eagle Rock Pipeline, L.P., which became our operating partnership, in exchange for 5,455,050 common units in Eagle Rock Pipeline, L.P. In June 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P. for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline, L.P. In addition, if Midstream Gas Services, L.P. achieves certain financial objectives for the year ending December 31, 2007, we will issue up to 798,155 of our common units as a contingent earn-out payment to Natural Gas Partners VII, L.P., as the primary equity owner of Midstream Gas Services. Upon completion of the initial public offering, the 6,580,466 common units in Eagle Rock Pipeline, L.P. were converted into common units in Eagle Rock Energy Partners, L.P. on approximately a 1-for-0.719 common unit basis. All of these interests in Eagle Rock Pipeline were converted into common units in us upon consummation of the initial public offering.
Item 6.
Item 6.
Selected Financial Data.
The financial data should be read in conjunction with our audited consolidated financial statements included in the Index to Consolidated Financial Statements on page of this Report. See also Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion analyzes our financial condition and results of operations. The following discussion of our financial condition and results of operations should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this Annual Report.
Overview
We are a Delaware limited partnership formed in March 2006 to own and operate the assets that have historically been owned and operated by Eagle Rock Pipeline, L.P. and its subsidiaries. In 2002, certain members of our management team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas producers. In connection with the acquisition in 2003 of the Dry Trail plant (subsequently sold in July 2004), a CO2 tertiary recovery plant located in the Oklahoma panhandle, members of our management team and Natural Gas Partners formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to own, operate, acquire and develop complementary natural gas midstream assets. Our growth is organic as well as through acquisitions. We have grown significantly through acquisitions, including the acquisitions of:
•
our Texas Panhandle Systems from ONEOK Texas Field Services, L.P.;
•
our Brookeland processing plant and system and Masters Creek system from Duke Energy Field Services, L.P. and Swift Energy Corporation;
•
our pro-rata undivided interests in the Indian Springs processing plant and Camp Ruby gathering system, both of which are operated by an affiliate of Enterprise Products Partners, L.P.; and
•
Midstream Gas Services, L.P.
Our organic growth projects include the expansion and extension of our gathering systems in the Texas Panhandle (East-West gathering pipeline) and our Tyler County pipeline and extension allowing for flexibility between our southeast Texas and Louisiana System (Brookeland, Masters Creek and Indian Springs), as well as increasing gas well comments and processing plants modifications. In addition, we will, in the first half of 2007, be extending our Tyler County pipeline and a start up of an idle processing plant in the Texas Panhandle Systems.
We believe we have significant opportunities for continued expansion of our existing gathering and processing systems in order to increase the capacity, efficiency and profitability of these systems through the implementation of commercial and operational development projects.
Our Operations
Our results of operations for our Texas Panhandle Systems and our southeast Texas and Louisiana System are determined primarily by the volumes of natural gas gathered, compressed, treated, processed and transported through our gathering, processing and pipeline systems and the associated commodity prices for natural gas, NGLs and condensate. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn cash fees for the services we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs.
Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our 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.
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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, however, in commodity prices 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. As of December 31, 2006, these arrangements accounted for approximately 11% of our natural gas volumes.
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Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport the gas through our gathering system, process the gas and sell the processed gas and/or NGLs at prices based on published index prices. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. We regard the margin from this type of arrangement, that is, the sale proceeds less amounts remitted to the producers, 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. We refer to contracts in which we share only in specified percentages of the proceeds from the sale of NGLs and in which the producer receives 100% of the proceeds from natural gas sales, as “percent-of-liquids” arrangements. Under percent-of-proceeds arrangements, our margin correlates directly with the prices of natural gas and NGLs and under percent-of-liquids arrangements, our margin correlates directly with the prices of NGLs (although there is often a fee-based component to both of these forms of contracts in addition to the commodity sensitive component). As of December 31, 2006, these arrangements accounted for about 77% of our natural gas volumes. Approximately 76% of the percent-of-proceeds volumes as of December 31, 2006 also have fee components.
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Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either 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) conditioning floors that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash fees for ancillary services, such as gathering, treating and compressing. As of December 31, 2006, these arrangements accounted for about 10% of our natural gas volumes. Approximately 74% of these keep-whole arrangements have fee components.
In addition, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of NGL volumes under percent-of-proceed and keep-whole contracts in 2006 and 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also hedged substantially all of our share of NGL volumes under percent-of-proceed contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to cover substantially all of our short natural gas position associated with our keep-whole volumes. We anticipate after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our Brookeland/Masters Creek acquisition. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs
under percent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
The following is a summary of the contracts that are significant to our operations, which contracts consist of a natural gas liquids exchange agreement, a gathering and processing agreement and four gas purchase agreements.
ONEOK Hydrocarbon. We are a party to a natural gas liquids exchange agreement with ONEOK Hydrocarbon, L.P., dated December 1, 2005. We deliver all of our natural gas liquids extracted at six of our natural gas processing plants in the Texas Panhandle to ONEOK for transportation and fractionation services. We take title to all of these volumes and they are physically delivered to Conway, Kansas where mid-continent type natural gas liquids pricing is available, with an option to exchange certain volumes at Mont Belvieu, Texas where gulf coast type natural gas liquids pricing is available. The primary contract term expires on June 30, 2010, of which an extension to June 30, 2015, may be mutually agreed to by the parties.
Chesapeake Energy Marketing. We are a party to a natural gas purchase agreement with Chesapeake Energy Marketing Inc., dated July 1, 1997, whereby we purchase raw natural gas from a number of wells on acreage dedicated to us located in Moore and Carson Counties, Texas. The natural gas from these wells is delivered into our Stinnett and Cargray gathering and processing systems. The acreage dedication under this contract is for the life of the leases from which the natural gas is produced. We pay Chesapeake an index posted gas price, less a fixed charge and fixed commodity fee and a fixed fuel percentage. Under this contract, there is an annual option to renegotiate the fuel and fees components. The original agreement was between MC Panhandle, Inc. and MidCon Gas Services Corp. and, as a result of ownership changes, the contract is now between Chesapeake and us.
Anadarko E&P. We are a party to a gas gathering and processing agreement with Anadarko E & P Company LP, dated September 1, 1993, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Jasper and Newton Counties, Texas. The natural gas from these wells is delivered into our Brookeland gathering system and plant. The acreage dedication under this contract is for the life of the leases from which the natural gas is produced. We receive a percentage of the natural gas liquid value and a percentage of the natural gas residue value for gathering and processing services. The original agreement was between Union Pacific Resources Company and Sonat Exploration Company and, as a result of ownership changes, the contract is now between Anadarko and us.
Ergon Energy Partners, L.P. We are a party to a gas purchase agreement with Ergon Energy Partners, L.P., dated September 1, 2005, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Tyler County, Texas. The natural gas from these wells is delivered to our Tyler County pipeline system. The term of this contract runs through September 30, 2011. We receive a percentage of the natural gas liquid value and fees for gathering and processing services.
Cimarex Energy Marketing. We are a party to a gas purchase agreement with Cimarex Energy Co., dated March 28, 1994, whereby we gather and process raw natural gas from a number of wells on acreage dedicated to us located in Roberts and Hemphill Counties, Texas, delivered to our Canadian processing plant. This is a life of lease contract. We receive a percentage of the natural gas liquid value and a percentage of the natural gas residue value for gathering and processing services. The original agreement was between Warren Petroleum Company and Wallace Oil & Gas, Inc. and, as a result of ownership changes, the contract is now between Cimarex and us.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. We view these measurements as important factors affecting our profitability and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, margin, operating expenses, and Adjusted EBITDA on a company-wide basis.
Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and
obtain new supplies is impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines, (2) our ability to compete for volumes from successful new wells in other areas and (3) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.
Margins. As of December 31, 2006, our overall portfolio of processing contracts reflected a net short position in natural gas of approximately 5,810 MMBtu/d (meaning we were a net buyer of natural gas) and a net long position in NGLs (including condensate) of approximately 6,877 Bbls/d (meaning we were a net seller of NGLs). As a result, during this period, our margins were positively impacted to the extent the price of NGLs increased in relation to the price of natural gas and were adversely impacted to the extent the price of NGLs declined in relation to the price of natural gas. We refer to the price of NGLs in relation to the price of natural gas as the fractionation spread. This portfolio performed well in response to favorable fractionation spreads during these periods. Because of the hedging program of our commodity risk, we have been able to develop overall favorable fractionation spreads within a range and we anticipate our unit margins will not be subject to significant downward fluctuations in commodity prices were to change in an unfavorable relationship.
Risk Management. For the year ended December 31, 2006, our risk management portfolio value changes reflected a $26.3 million unrealized non-cash loss recorded to Total Revenues for our natural gas, natural gas liquids and condensate associated derivatives. In addition, we recorded $2.8 million unrealized non-cash gain within Interest and Other Expense related to the interest rate swaps associated with our credit agreement. As both of the unrealized positions reflect underlying commodity prices and interest rates both in the short and long-term, the unrealized value position will be subject to variability from period to period.
Operating Expenses. Operating expenses are a separate measure we use to evaluate operating performance of field operations. Direct labor, insurance, repair and maintenance, utilities and contract services comprise the most significant portion of our operating expenses. These expenses are largely independent of the volumes through our systems, but fluctuate depending on the activities performed during a specific period. We do not deduct operating expenses from total revenues in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.
Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus income tax, interest-net, depreciation and amortization expense, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations. Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash charge which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations.
Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.
General Trends and Outlook
We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Supply, Demand and Outlook. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.2 trillion cubic feet, or Tcf, in 2005 to approximately 22.35 Tcf in 2010. During the last three years, the United States has on average consumed approximately 22.3 Tcf per year, while total marketed domestic production averaged approximately 18.5 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.
We believe current natural gas prices and the existing strong demand for natural gas will continue to result in relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the natural gas reserves in the United States have increased overall in recent years, a corresponding increase in production has not been realized. We believe this lack of increased production is attributable to insufficient pipeline infrastructure, the continued depletion of existing wells and a tight labor and equipment market. We believe an increase in United States natural gas production, additional sources of supply such as liquid natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for natural gas in the United States.
Most of the areas in which we operate are experiencing significant drilling activity. Although we anticipate continued high levels of exploration and production activities in substantially all of the areas in which we operate, 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.
Impact of Interest Rates and Inflation. The credit markets have experienced historically lows in interest rates over the past several years. If the overall United States economy continues to strengthen, we believe it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this 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, as our competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations in 2005 or 2006. 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.
Financial Statement Presentation and Comparability of Financial Results
Our historical financial statements consist of:
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The financial statements of Eagle Rock Pipeline, L.P., as the accounting acquirer of ONEOK Texas Field Services, L.P., and the entity contributed to Eagle Rock Energy Partners, L.P., in connection with our initial public offering. For a discussion of the results of operations of Eagle Rock Pipeline, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Eagle Rock Pipeline Results of Operations. The financial statements of Eagle Rock Pipeline, together with the notes thereto, are also included elsewhere in this report.
Our historical results of operations for the periods presented may not be comparable, either from period to period or going forward, for the reasons described below:
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We have grown rapidly through acquisitions. Our acquisitions were completed at different dates and with numerous sellers and were accounted for using the purchase method of accounting. Under the purchase method of accounting, results from such acquisitions are recorded in the financial statements only from the date of acquisition.
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On December 5, 2003, Eagle Rock Pipeline commenced operations by acquiring the Dry Trail plant from Williams Field Service Company for approximately $18.0 million, and in July 2004, Eagle Rock Pipeline sold the Dry Trail plant to Celero Energy, L.P. for approximately $37.4 million, resulting in a pre-tax realized gain on the disposition of approximately $19.5 million in 2004. The Dry Trail operations are reflected as discontinued operations for Eagle Rock Pipeline for 2003 and 2004.
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In connection with our acquisition of Eagle Rock Predecessor on December 1, 2005, the book basis of the assets of Eagle Rock Predecessor was increased to reflect the purchase price, which had the effect of increasing the depreciation expense associated with the assets of Eagle Rock Energy Partners, L.P.
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As a result of our increased debt related to the acquisition of Eagle Rock Predecessor, our interest expense increased subsequent to December 1, 2005.
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After our acquisition of Eagle Rock Predecessor, we initiated a risk management program comprised of NGL puts, costless collars and swaps, crude costless collars and natural gas calls, as well as interest rate swaps that we accounted for using mark-to-market accounting. These amounts are included in unrealized/realized gain (loss) from risk management activities.
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We completed construction of the Tyler County pipeline on February 28, 2006, which was flowing 28.4 MMcf/d of natural gas to the Indian Springs processing plant as of December 31, 2006. As a result, our historical financial results for periods prior to March 31, 2006, do not include the financial results from the operation of this asset.
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On March 27, 2006, Eagle Rock Pipeline completed a private placement of 5,455,050 common units for $98.3 million to fund our Brookeland/Masters Creek acquisition. These common units in Eagle Rock Pipeline were converted into common units in us upon consummation of our initial public offering on approximately a 1-for-0.719 common unit basis.
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On March 31, 2006, we purchased an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line from Duke Energy Field Services. On April 7, 2006, we purchased the remaining interest in the Brookeland and Masters Creek facilities owned by Swift Energy Corporation for a total purchase price of approximately $95.7 million. The acquired assets are located in southeast Texas and complement our existing southeast Texas assets. As a result, our historical financial results for periods prior to March 31, 2006 do not include the financial results from our ownership of these assets.
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On June 2, 2006, we purchased all of the partnership interests in Midstream Gas Services, L.P. for approximately $4.7 million in cash and 1,125,416 common units in Eagle Rock Pipeline. These common units in Eagle Rock Pipeline were converted into common units in us upon consummation of our initial public offering on approximately a 1-for-0.719 common unit basis. We will issue up to 798,155 of our common units (pre-IPO units), which we refer to as the Deferred Common Units, to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. The acquired operations are located in Roberts County in the Texas Panhandle within our East Panhandle System. We expect this acquisition to provide significant synergies and gathering and processing capacity and to enhance our strategic presence in the area. As a result, our historical financial results for the periods prior to June 2, 2006, do not include the financial results from our ownership of these interests.
Critical Accounting Policies and Estimates
Conformity with accounting principles generally accepted in the United States requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an on-going basis, we make and evaluate estimates and judgments based on management’s best available knowledge of previous, current, and expected future events. Given that a substantial portion of our operations were acquired within the past twelve months, we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or
assumptions. Currently, we do not foresee any reasonably likely changes to our current estimates and assumptions which would materially affect amounts reported in the financial statements and notes. We have selected the following critical accounting policies that currently affect our financial condition and results of operations for discussion.
Revenue and Cost of Sales Recognition. We record revenue and cost of sales on the gross basis for those transactions where we act as the principal and take title to natural gas, NGLs or condensates that is purchased for resale. When our customers pay us a fee for providing a service such as gathering, treating or transportation we record the fees separately in revenues.
We currently record the monthly results of operations using primarily actual results which include settling most of our volumes with producers, shippers and customers around the 25th of the month following the production month. This process results in us reporting later than other similar partnerships that report on estimates.
Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks. These hedging activities rely upon forecasts of our expected operations and financial structure over the next five 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.
From the inception of our hedging program in October 2005 through December 2006, we used mark-to-market accounting for our commodity hedges and interest rate swaps. There were no derivatives for the periods before September 30, 2005. For the twelve months ended December 31, 2006, we incurred $24.0 million of realized and unrealized losses within total revenue related to our commodity risk management activities. This consisted of $2.3 million in net realized gain and $26.3 million of net unrealized loss. Within the interest and other expense section, we recorded $3.3 million of realized and unrealized gain related to our credit facility interest rate risk management activities. These consisted of $0.5 million realized net gain and a $2.8 million net unrealized gain. We recorded monthly realized gains and losses on hedge instruments based upon cash settlements information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record unrealized gains and losses quarterly based upon the future value on mark-to-market hedges through their expiration dates. The expiration dates vary but are currently no later than January 2011 for our interest rate hedges, and December 2010 for our commodity hedges. The option premium costs we incurred as part of our Panhandle acquisition are being expensed through the unrealized risk management instruments in total revenue. We monitor and review hedging positions regularly.
Depreciation Expense and Cost Capitalization Policies. Our assets consist primarily of natural gas gathering pipelines and processing plants. 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. The cost of funds used in construction represents capitalized interest. These costs are then expensed over the life of the constructed asset through the recording of depreciation expense.
As discussed in Note 2 to the Consolidated Financial Statements, depreciation of our assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments which extend the useful life of property, plant and equipment are also capitalized. The costs of repairs, replacements and maintenance projects are expensed as incurred.
The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.
Impairment of Long-Lived Assets - We assess our long-lived assets for impairment based on SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. A long-lived asset is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair
value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.
Examples of long-lived asset impairment indicators include:
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a significant decrease in the market price of a long-lived asset or asset group;
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a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;
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a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;
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an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group;
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a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
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a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
Environmental Remediation. Current accounting guidelines require us to recognize a liability and expense associated with environmental remediation if (i) government agencies mandate such activities or one of our properties were added to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) database, (ii) the existence of a liability is probable and (iii) the amount can be reasonably estimated. To date, we have recorded a $0.3 million liability for remediation expenses. If governmental regulations change, we could be required to incur additional remediation costs which may have a material impact on our profitability.
As a result of the adoption of Statement of Financial Accounting Standards, or SFAS, No. 143 Accounting for Asset Retirement Obligations, Eagle Rock Pipeline has recorded a long-term liability of approximately $1.8 million, primarily consisting of the Panhandle and Brookeland asset acquisitions. Related accretion expense has been recorded in operating expenses and depreciation and amortization expense has also been recorded. See Note 2.
Eagle Rock Pipeline Results of Operations
The following table is a summary of the results of operations of Eagle Rock Pipeline for the three years ended December 31, 2006, 2005 and 2004.
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Segment gross margin consists of total revenues less cost of natural gas and NGLs. Please read “Summary - Non-GAAP Financial Matters.”
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Adjusted EBITDA consists of net income plus income tax, interest-net, depreciation and amortization expense, other non-cash operating expenses less non realized revenues risk management loss (gain) activities and less net income from discontinued operations.
Year Ended December 31, 2006 Compared with Year Ended December 31, 2005
Financial results for the twelve months ended December 31, 2006, include activities of the ONEOK Texas Field Services, L.P. assets (“Panhandle Assets”) (acquired in December 2005), Brookeland assets (acquired in March and April 2006) and acquisition of MGS (acquired in June 2006).
Operating revenues for sales of natural gas, NGLs and condensate increased by $427.0 million, primarily from the Panhandle Assets (twelve months of contribution in 2006 versus one month in 2005), Brookeland assets and MGS acquisitions and the contribution from the newly constructed Tyler County pipeline during the latter part of 2006. The increase of $8.6 million in revenues for compression, gathering and processing services was also favorably impacted by the increased activities from the acquired assets.
As a result of our commodity hedging activities, total revenues include a realized gain of $2.3 million on risk management investments that were settled for the twelve month period and an unrealized mark-to-market net loss of $26.3 million which includes the fair value change of the option premiums associated with the Panhandle Assets. As the forward price curves for our hedged commodities shift in relation to the caps, floors, swap and strike prices at which we have executed our derivative instruments, the fair market value of such
instruments changes through time. The mark-to-market net unrealized loss reflects overall unfavorable forward curve price movements during the twelve months period for the underlying commodities for the derivative instruments. The net unrealized loss is comprised of $18.6 million gain related to our NGL position and crude oil as the forward curve prices in these commodities decreased during the quarter. Partially offsetting the unrealized gain, we recorded an unrealized net loss of $25.7 million related to natural gas forward curve price movements during the year. The $19.2 million remaining difference refers to the amortization of the put premiums as the underlying options have expired. The unrealized net loss of $26.3 million did not have a significant impact on cash activities for the 2006 period.
Given the uncertainty surrounding future commodity prices, and the general inability to predict these as they relate to the caps, floors, swaps and strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in the future. Conversely, negative commodity price movements affecting our revenues and costs are expected to be compensated by our executed derivative instruments.
Purchase of natural gas and NGLs increased by $322.3 million reflecting the cost of goods expense for the increased sales of natural gas, NGLs and condensate revenue as discussed above.
Segment gross margin increased by $82.4 million reflecting the increased business activity in revenues and purchases, as discussed above. Reducing segment gross margin for the twelve months 2006 period is the $26.3 unrealized mark-to-market loss related to our risk management activities as described above. Excluding this amount, segment gross margin would have been $127.1 million as compared to $11.1 million for the 2005 twelve month period.
Operations and maintenance expense increased by $30.0 million for the year ended 2006 compared to 2005, due to the increased operations from the acquired assets as well as from the first phase of the Tyler County pipeline project completed earlier in 2006.
General and administrative expense also increased by $8.4 million, as the Partnership built up its corporate infrastructure and personnel to manage the acquired assets and public partnership expenses. Included in general and administrative expense is property tax, total employee benefit programs and the Partnership’s property and liability insurance programs.
Adjusted EBITDA for the 2006 year was $81.2 million as compared to $3.4 million for 2005. The increase is primarily from the contribution of the acquired assets, as well as the contribution from the Tyler County Pipeline project.
During the fourth quarter of 2006, Holdings paid $6.0 million at the time of the initial public offering to terminate the advisory services agreement with Natural Gas Partners. The transaction was recorded as an expense on the Partnership’s income with the offset to members’ equity.
As the purchase price of the acquired assets was allocated and pushed down to the operating entities’ balance sheets, depreciation and amortization expense also increased by $39.1 million from the associated higher fixed assets and intangible assets of the acquired assets, as well as additions during the year.
As the Panhandle acquisition was substantially financed with a credit loan facility, interest expense, net increased by $23.7 million, including interest swap realized gain of $0.5 million. We did not have outstanding debt prior to the Panhandle Assets acquisition in 2005. Included in interest expense for 2006 is approximately $0.4 million of direct cost expensed related to the amended and restated credit agreement which became effective on August 31, 2006, as well as higher debt issuance cost amortization during 2006.
We recorded an unrealized mark-to-market gain of $2.8 million related to our interest rate risk management position. The unrealized gain relates to our future periods interest swaps and from changes during the year in the underlying interest rate associated with the derivatives. The unrealized mark-to-market gain did not have a significant impact on cash activities during the 2006 period.
We recorded $1.2 million of income taxes related to temporary differences caused by the Texas entity level tax to become effective in 2008.
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004
Financial results as of December 31, 2005, include one month of operations of the Panhandle Assets acquired on December 1, 2005, and are, therefore, not directly comparable to results as of December 31, 2004. Prior to this acquisition, Eagle Rock Pipeline owned pro-rata, non-operated interests in the Indian Springs and Camp Ruby assets, and had begun construction of the Tyler County pipeline. With the Panhandle acquisition, revenue increased by $63.1 million, cost of natural gas and NGLs increased by $46.5 million, and operating and maintenance expense increased by $2.9 million, from December 31, 2004 to December 31, 2005. This significant increase in results is directly attributable to the relative large scale of the assets acquired in relation to our previously existing business. General and administrative expenses also increased by $2.4 million, as Eagle Rock Pipeline built up its corporate infrastructure and personnel to manage the acquired assets. Depreciation and amortization expense increased by $3.5 million, as a result of the Panhandle acquisition. As the Panhandle acquisition was partly financed with a $400.0 million term loan facility, interest expense increased by $4.0 million, including interest rate swap unrealized losses of $1.6 million, whereas we were previously unleveraged as of December 31, 2004. During the year ended December 31, 2004, $22.2 million was recognized as income from discontinued operations related to the gain on the sale and the results of operations of the Dry Trail plant in 2004.
Other Matters
Hurricanes Katrina and Rita. Hurricanes Katrina and Rita struck the Gulf Coast region of the United States on August 29, 2005 and September 24, 2005, respectively, causing widespread damage to the energy infrastructure in the region. The storms did not cause material direct damage to any of our assets in the region. While neither Hurricane Katrina nor Hurricane Rita caused material direct damage to our facilities, Hurricane Rita did disrupt the operations of NGL pipelines and fractionators in the Houston, Texas area and caused power outages to some of our producers in the southeast Texas area. As a result of these disruptions, we were forced to temporarily curtail certain of our producers in the region for approximately four days and to operate our Indian Springs facility in a reduced recovery mode for approximately six days.
Wild fires in Texas Panhandle. Wild fires in the Texas Panhandle during the week of March 11, 2006, temporarily affected our operations in the region. While the fires did not cause material direct damage to our facilities, some experienced down-time was caused by power outages at the local electric co-ops. Our Lefors and Cargray plants came back up with reduced flow rates as producers had shut-in their production during the fires. There was minimal and temporary damage sustained in the field to a very small number of metering facilities and one flow line. Less than $0.1 million was spent on repairs caused by the fires. The overall economic impact has been estimated to be between $0.5 million and $1.0 million.
Environmental. A Phase I environmental study was performed on our Texas Panhandle assets by an environmental consultant engaged by us in connection with our pre-acquisition due diligence process in 2005. As a result of performing the Phase I environmental study, we are planning to conduct environmental investigations at 11 properties, the costs of which are estimated to collectively range between $0.2 million and $0.4 million and for which we have accrued reserves in the amount of $0.3 million as of December 31, 2005, with no change for the 2006 year. Depending on the findings made during those investigations, and in anticipation of implementing amended SPCC plans at multiple locations as well as performing selected cavern closures, we estimate that an additional $1.2 million to $2.5 million in costs could be incurred by us in resolving environmental issues at those properties. We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, (1) we are entitled to indemnification with respect to certain environmental liabilities retained by prior owners of these properties, and (2) we purchased an environmental pollution liability insurance policy. The policy pays for on-site clean-up as well as costs and damages to third parties and currently has a one-year term with a $5.0 million limit subject to a $0.5 million deductible. We expect to renew this policy on an annual basis.
Liquidity and Capital Resources
Historically, our sources of liquidity have included cash generated from operations, equity investments by our owners and borrowings under our credit facilities.
With the completion of the IPO offering, we expect our sources of liquidity to include:
•
cash generated from operations;
•
borrowings under our credit facilities;
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debt offerings; and
•
issuance of additional partnership units.
We believe the cash generated from these sources will be sufficient to meet our minimum quarterly cash distributions and our requirements for short-term working capital and capital expenditures for the next twelve months.
Cash Flows
Since the formation of Eagle Rock Pipeline, L.P. in 2005 through December 31, 2006, several key events having major impacts on our cash flows are:
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the acquisition of the midstream assets in the Texas Panhandle on December 1, 2005 for approximately $531.1 million, which was financed through an additional equity contribution of $133.0 million and debt of $400.0 million, not including $27.5 million in risk management costs related to option premiums; and
•
the acquisition of the Brookeland gathering and processing facility and related assets on March 31, 2006 and April 7, 2006 for approximately $95.8 million, which we financed entirely with equity.
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the acquisition of all of the partnership interests in Midstream Gas Services, L.P. on June 2, 2006 for approximately $25.0 million which we paid with $4.7 million in cash and $20.3 million in Eagle Rock Pipeline, L.P. units.
Working Capital (Deficit). Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our liabilities as they become due. The working capital was $12.1 million at December 31, 2006 and $29.2 million as of December 31, 2005.
The net decrease in working capital of $17.1 million from December 31, 2005 to December 31, 2006, resulted primarily from the following factors:
•
cash balances decreased overall by $8.8 million and was impacted from the results of operations, timing of cash receipts and disbursements, as well as capital expenditures levels;
•
risk management net working capital balance decreased by a net $8.0 million as a result of the changes in the mark-to-market unrealized positions and fair value changing of the option premiums;
•
prepayments and other current assets increased by $1.4 million primarily from the property and liability prepaid insurance balances;
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accounts payable decreased by $2.7 million from December 31, 2006, primarily as a result of timing of payments and impacts from commodity price changes for natural gas and NGLs; and
•
accrued liabilities increase of $14.6 million primarily reflects accrued interest for the credit agreement, property tax accruals, employee paid absence liability and other accruals.
Cash Flows Year Ended 2006 Compared to Year Ended 2005
Cash Flow from Operating Activities. Increase of $56.7 million during the current year is the result of increased income from both the acquired assets and the growth capital expenditure projects.
Cash Flows From Investing Activities. Cash flows used in investing activities for the year ended December 31, 2006, as compared to the year ended December 31, 2005, decreased by $408.4 million. The investing activities for the current year reflect the Brookeland and MGS acquisition assets, $101.2 million, as well as a higher capital expenditure level of $38.4 million versus $4.2 million for the year ended 2005. In addition, cost for acquiring intangibles, primarily pipeline rights-of-way is a $2.2 million increase between the two years. The capital expenditure amount for the current year reflects the Tyler County pipeline extensions, Red Deer processing plant refurbishment and start up, East-West gathering pipeline, other growth programs, as well as, maintenance and well connect capital outlays. For 2005, the Panhandle acquisition comprised $531.1 million of the investing activities.
Cash Flows From Financing Activities. Cash flows provided by in financing activities for the year ended December 31, 2006, decreased by $485.2 million, over the year ended December 31, 2005. Key differences between years include $407.6 million in Revolver and Term Loan borrowings in 2005 as compared to a $2.7 million net repayment in 2006, $98.5 million of equity contribution before the initial public offering in 2006 versus $192.4 million contributed in 2005 (both are primarily the equity contributions associated with the Texas Panhandle asset acquisition in 2005 and the Brookeland and MGS acquisitions in 2006). In addition, payments of $27.5 million for derivative contracts, primarily the put contracts related to the Texas Panhandle asset acquisition, were made in 2005. Distributions, not including the IPO-related distributions, were a cash outflow of $22.0 million in 2006, as compared to $9.7 million in 2005. Net cash inflow from the initial public offering, including the overallotment, was primarily used for distributions to pre-IPO members for capital expenditure and working reimbursements, arrearage distributions and units purchased for the overallotment, as well as issuance costs related to the initial public offering.
Capital Requirements
The midstream energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:
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growth capital expenditures, which are made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities; or
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maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to meet regulatory requirements, to maintain the existing operating capacity of our assets and extend their useful lives or to maintain existing system volumes and related cash flows.
For the December 31, 2006 year, we spent $38.4 million for capital expenditures, $27.1 million for growth and $11.3 million for maintenance. Growth includes the Tyler County pipeline as well as the East-West gathering pipeline in the Texas Panhandle Systems and the Red Deer processing plant project. We have budgeted approximately $42.1 million in capital expenditures for the year ended December 31, 2007, of which $30.8 million represents growth capital expenditures and approximately $11.3 million represents maintenance capital expenditures. For the year ended December 31, 2005, our growth capital expenditures were $4.8 million and our maintenance capital expenditures were $0.0 million, including non-cash expenditures in accounts payable.
Since our inception in 2002, we have made substantial growth capital expenditures, including those relating to the acquisition of the Dry Trail plant, the Camp Ruby gathering system, the Indian Springs processing plant, the Panhandle Assets and the Brookeland and Masters Creek gathering and processing assets. We anticipate we will continue to make significant growth capital expenditures and acquisitions. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives.
We continually review opportunities for both organic growth projects and acquisitions which will enhance our financial performance. Because we will distribute most of our available cash to our unitholders, we will depend on borrowings under our amended and restated credit facility and the incurrence of debt and equity securities to finance any future growth capital expenditures or acquisitions. The upward trend in interest rates
experienced recently will increase our borrowing costs on additional debt financing incurred to finance future acquisitions, as compared to our borrowing costs under our currently hedged credit facility.
Amended and Restated Credit Agreement
On August 31, 2006, we entered into an amended and restated credit facility which provides for $300.0 million aggregate principal amount of Series B Term Loans and up to $200.0 million aggregate principal amount of revolving commitments. The amended and restated credit agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the revolver. In addition, the credit facility allows us to expand the Term and Revolving Commitment up to an additional $100.0 million if certain financial conditions are met. At December 31, 2006, we had $299.3 million outstanding under the term loan, $105.4 million outstanding under the revolver and $2.5 million of outstanding letters of credit.
At our election, the term loan and the revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the adjusted Eurodollar rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, we elected the Eurodollar rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin will increase by 0.50% per annum on January 31, 2007, a result of the Partnership not pursuing a rating by both S&P and Moody’s, per the agreement.
Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar rate loans are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by us. Interest on the term loans is paid each December 31, March 31, June 30 and September 30 of each year, commencing on September 30, 2006. We pay a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage shall increase by 0.25% per annum on January 31, 2007. We also pay a letter of credit fee equal to (1) the applicable margin for revolving loans that are Eurodollar rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such letters of credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, we pay a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.
The obligations under the amended and restated credit agreement are secured by first priority liens on substantially all of our assets, including a pledge of all of the capital stock of each of our subsidiaries. In addition, the credit facility contains various covenants limiting our ability to incur indebtedness, grant liens and make distributions and certain financial covenants requiring us to maintain:
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an interest coverage ratio (the ratio of our consolidated Adjusted EBITDA to our consolidated interest expense, in each case as defined in the credit agreement) of not less than 2.5 to 1.0, determined as of the last day of each quarter for the four quarter period ending on the date of determination; and a leverage ratio (the ratio of our consolidated indebtedness to our consolidated Adjusted EBITDA, in each case as defined in the credit agreement) of not more than 5.0 to 1.0 (or, on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than 5.25 to 1.0).
We will use the available borrowing capacity under our amended and restated credit facility for working capital purposes, maintenance and growth capital expenditures and future acquisitions. The Partnership has approximately $80.0 million of unused capacity under the agreement with availability as of December 31, 2006, of approximately $24.0 million.
Off-Balance Sheet Obligations. We have no off-balance sheet transactions or obligations.
Debt Covenants. At December 31, 2006, we were in compliance with the covenants of the credit facilities.
Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2006. All of the $405.7 million of term loans outstanding on December 31, 2006 are scheduled for interest rate resets on three-month intervals. Interest rates were last reset for all amounts outstanding on December 31, 2006.
(1)
Assumes our fixed swapped average interest rate of 4.92% plus the applicable margin under our amended and restated credit agreement, which remains constant in all periods.
(2)
Excludes physical and financial purchases of natural gas, NGLs, and other energy commodities due to the nature of both the price and volume components of such purchases, which vary on a daily or monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.
Recent Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board, or the FASB, issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership adopted SFAS No. 155 on January 1, 2007, and does not expect this standard to have a material impact, if any, on our combined financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159), which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.
In October 2005, the FASB issued Staff Position FAS 13-1 concerning the accounting for rental expenses associated with operating leases for land or buildings which are incurred during a construction period. We considered how this might apply to our payment for rights-of-way associated with the construction of pipelines, and we do not anticipate any changes to our accounting practices or impacts on our results of operations or financial condition in light of this recently issued Staff Position.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect that the adoption of FIN 48 will have a material impact on our results of operations or financial position.
Recent Developments
On February 7, 2007, the Partnership declared a $0.3625 distribution per common unit for the fourth quarter of 2006, prorated to $0.2679 per common unit for the timing of the initial public offering on October 24, 2006. The distribution to the common units was paid on February 15, 2007. No distribution was made to the subordinated or general partners for the quarter.
On April 2, 2007, the Partnership announced it has signed a definitive purchase agreement to acquire Laser Midstream Energy, L.P. and certain of its subsidiaries for $136.8 million, including $110.0 million in cash and 1,407,895 of common units of the Partnership. The assets subject to this transaction include over 405 miles of gathering systems and related compression and processing facilities in South Texas, East Texas and North Louisiana. The acquisition is subject to customary closing conditions and is expected to close in late April.
In addition, Eagle Rock announced that it has signed a definitive agreement to acquire certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. (a Natural Gas Partners VII, L.P. portfolio company) and NGP-VII Income Co-Investment Opportunities, L.P. (a Natural Gas Partners affiliate) for an aggregate purchase price of $127.6 million, subject to price adjustments. Montierra and such co-investment fund (collectively, “Montierra”) will receive as consideration a total of 6,400,000 EROC common units and $6.0 million in cash. The assets conveyed in this transaction include minerals acres, and interests in wells with net proved producing reserves of approximately 4.6 billion cubic feet of gas (unaudited) and 2.5 million barrels of oil (unaudited).
The Partnership also announced on April 2, 2007, it has entered into a unit purchase agreement to sell in a private placement 7,005,495 common units to third-party investors, for total cash proceeds of $127.5 million. The Partnership also has agreed to file a registration statement with the SEC registering for resale the common units within 90 days after the closing. The proceeds from this equity private placement will fully fund the cash portion of the purchase price of the Laser acquisition. The Partnership anticipates that the private placement will close simultaneously with the Laser acquisition.
In addition, the Partnership has received $100 million in additional commitments to increase its revolver facility under its existing Amended and Restated Credit Facility. The increase of the revolver provides the Partnership with approximately $175 million in borrowing availability.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
Risk and Accounting Policies
We are exposed to market risks associated with commodity prices, counterparty credit and interest rates. Our management has established a comprehensive review of our market risks and is developing risk management policies and procedures to monitor and manage these market risks. Our general partner is responsible for delegation of transaction authority levels, and with the planned establishment of a Risk Management Committee, our general partner will be responsible for the overall approval of market risk management policies. The Risk Management Committee will be composed of directors (including, on an ex
officio basis, our chief executive officer) who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee will be responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.
See “- Critical Accounting Policies and Estimates - Risk Management Activities” for further discussion of the accounting for derivative contracts.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and other commodities as a result of our gathering, processing and marketing activities, which produce a naturally long position in NGLs and a natural short position in natural gas. We attempt to mitigate commodity price risk exposure by matching pricing terms between our purchases and sales of commodities. To the extent that we market commodities in which pricing terms cannot be matched and there is a substantial risk of price exposure, we attempt to use financial hedges to mitigate the risk. It is our policy not to take any speculative marketing positions.
Both our profitability and our cash flow are affected by volatility in prevailing natural gas and NGL prices. Natural gas and NGL prices are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. Historically, changes in the prices of heavy NGLs, such as natural gasoline, have generally correlated with changes in the price of crude oil. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors.” Adverse effects on our cash flow from increases in natural gas prices and decreases in NGL product prices could adversely affect our ability to make distributions to unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in our areas of operations, and the use of derivative contracts. Our overall direct exposure to movements in natural gas prices is managed to minimize the risk of our natural short position for 2006 and 2007, the periods for which we have hedged our natural gas exposure to this point, as well as a result of natural hedges inherent in our contract portfolio. Natural gas prices, however, can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our service. We are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices. NGL prices have experienced volatility in recent years in response to changes in the supply and demand for NGLs and market uncertainty. In response to this volatility, we have instituted a hedging program to reduce our exposure to commodity price risk. Under this program, we have hedged substantially all of our share of expected NGL volumes under percent-of-proceed and keep-whole contracts in 2006 and 2007 through the purchase of NGL put contracts, costless collar contracts and swap contracts. We have also hedged substantially all of our share of expected NGL volumes under percent-of-proceed contracts from 2008 through 2010 through a combination of direct NGL hedging as well as indirect hedging through crude oil costless collars. Additionally, to mitigate the exposure to natural gas prices from keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 and entered into swaps for the months of August and September 2006 to cover substantially all of our short natural gas position associated with our keep-whole volumes. We anticipate that after 2007, our short natural gas position will become a long natural gas position because of our increased volumes in the Texas Panhandle and the volumes contributed from our Brookeland/Masters Creek acquisition. In addition, we intend to pursue fee-based arrangements, where market conditions permit, and to increase retained percentages of natural gas and NGLs under percent-of-proceed arrangements. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
We have not designated our contracts as accounting hedges under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. As a result, we mark our derivatives to market with the resulting change in fair value included in our statement of operations.
The following table sets forth certain information regarding our NGL options, valued as of December 31, 2006:
The following table sets forth certain information regarding our NGL fixed swaps, valued as of December 31, 2006:
The following table sets forth certain information regarding our crude oil options, valued as of December 31, 2006:
The following table sets forth certain information regarding our natural gas options, valued as of December 31, 2006:
Please see “Interest Rate Risk” for valuation of interest rate swaps.
The table below summarizes the changes in commodity and interest rate risk management assets for the applicable periods:
Credit Risk
Our purchase and resale of natural gas exposes us to credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability. We are diligent in attempting to ensure that we issue credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or parental guarantees.
Interest Rate Risk
The credit markets recently have experienced record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current
levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.
We are exposed to variable interest rate risk as a result of borrowings under our existing credit agreement.
In December 2005, we entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:
Item 8.
Item 8.
Financial Statements and Supplementary Data.
Our consolidated financial statements, together with the independent registered public accounting firm’s report of Deloitte & Touche LLP (“Deloitte & Touche”), begin on page of this Annual Report.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A.
Controls and Procedures.
Disclosure Controls
At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of the general partner of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a - 15(e) and 15d - 15(e) of the Exchange Act of 1934, as amended). Based on that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of the general partner of our general partner, concluded our disclosure controls and procedures were effective as of December 31, 2006, to provide reasonable assurance the information required to be disclosed by us in the reports we file or submit under the Exchange Act of 1934, as amended, are properly recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.
Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
In anticipation of becoming subject to the provisions of Section 404 of the Sarbanes-Oxley Act of 2002, we initiated, in late 2006, an evaluation and program of documentation, implementation and testing of internal control over financial reporting. This program will continue through 2007, culminating with our initial
Section 404 certification and attestation in early 2008. As of December 31, 2006, we have evaluated the effectiveness of our system of internal control over financial reporting, as well as changes therein, in compliance with Rule 13a-15 of the SEC’s rules under the Securities Exchange Act and have filed the certifications with this report required by Rule 13a-14.
In the course of that evaluation, we found no fraud, whether or not material, that involved management or other employees who have a significant role in our internal control over financial reporting and no material weaknesses. There have been no changes in our internal controls over financial reporting that occurred during the three months ended December 31, 2006, that have materially affected, or are reasonably likely to affect materially, our internal controls over financial reporting.
Item 9B.
Item 9B.
Other Information.
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
The following table shows information regarding the current directors and executive officers of Eagle Rock Energy G&P, LLC, which is the general partner of our general partner.
Because of its ownership of a majority interest in Eagle Rock Holdings, L.P., Natural Gas Partners has the right to elect all of the members of the board of directors of Eagle Rock Energy G&P, LLC. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by the member of Eagle Rock Energy G&P, LLC. The executive officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. The executive officers of Eagle Rock Energy G&P, LLC will devote all of their time to our business and operations.
Alex A. Bucher, Jr. was elected Chairman of the Board, President and Chief Executive Officer of Eagle Rock Energy G&P, LLC in August 2006 and served as Chairman of the Board until January 2007, when William J. Quinn succeeded Mr. Bucher as Chairman of the Board. Mr. Bucher continues to serve as a director. Mr. Bucher also served as President, Chief Executive Officer, Treasurer and Director of Eagle Rock Energy G&P, LLC from March 2006 until August 2006. Mr. Bucher serves as the Chairman of the compensation committee. Mr. Bucher has been Secretary, Chief Executive Officer and Director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 to December 2005. In June 2002, Mr. Bucher co-founded Eagle Rock Energy, Inc. and served as its President and Treasurer from June 2002 until December 2003. From November 1999 to June 2002, Mr. Bucher was Vice President of Operations and Vice President and Director of Business Development for MidCoast, subsequently Enbridge,
Inc., an energy transportation and distribution company. Prior to joining MidCoast, Mr. Bucher was Vice President and Regional Manager for Dynegy, Inc., a gas gathering and processing company.
Richard W. FitzGerald was elected Senior Vice President, Chief Financial Officer and Treasurer of Eagle Rock Energy G&P, LLC and Eagle Rock Pipeline, L.P. in August 2006. From May 2003 to August 2006, Mr. FitzGerald was Senior Vice President and Chief Financial Officer of Natco Group, Inc. From April 1999 to April 2003, Mr. FitzGerald was Senior Vice President and Chief Financial Officer of Universal Compression Inc. Prior to that, Mr. FitzGerald was Vice President of Financial Planning and Services for KN Energy from January 1998 to April 1999.
Alfredo Garcia was elected Senior Vice President, Corporate Development of Eagle Rock Energy G&P, LLC in August 2006. Mr. Garcia served as Senior Vice President and Chief Financial Officer of Eagle Rock Energy G&P, LLC from March 2006 until August 2006, and as Chief Financial Officer of Eagle Rock Pipeline, L.P. from December 2005 until August 2006 and Eagle Rock Energy, Inc. from February 2004 through December 2005. From March 1999 until February 2004, Mr. Garcia was founder and director of Investment Analysis & Management, LLC, a financial advisory and consulting firm. During this period, he also acted as Chief Financial Officer at TrueCentric, LLC, a software start-up company. Prior to this, Mr. Garcia was a Latin American Associate for HM Capital Partners, a private equity firm formerly known as Hicks Muse Tate & Furst.
William E. Puckett was elected Senior Vice President, Commercial Operations of Eagle Rock Energy G&P, LLC in March 2006. Mr. Puckett has been Vice President, Commercial Operations of Eagle Rock Pipeline, L.P. since December 2005. From September 1999 until November 2005, Mr. Puckett was Vice President, Technical Services for Dynegy, Inc., a gas gathering and processing company. Mr. Puckett has also served in a variety of positions in marketing, processing and operations.
J. Stacy Horn was elected Vice President, Commercial Development of Eagle Rock Energy G&P, LLC in March 2006. Mr. Horn has been Vice President, Commercial Development of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from October 2004 to December 2005. Prior to joining Eagle Rock Energy, Inc., Mr. Horn was Commercial Manager, Director of Business Development for El Paso Field Services, L.P., a natural gas gathering and processing and transportation company, from December 2000 to October 2004.
Stephen McNair was elected Vice President of Operations and Technical Services of Eagle Rock Energy G&P, LLC in August 2006. Mr. McNair has been Vice President of Natural Gas Services for TEPPCO in Denver, Colorado from March 2005 to July 2006. From September 2002 to January 2005, Mr. McNair was Vice President - Rocky Mountain Region for Duke Energy Field Services. Prior to that, Mr. McNair held the position of General Manager - West Permian Region for Duke Energy Field Service from April 2000 to August of 2002.
William J. Quinn was appointed Chairman of the Board of Eagle Rock Energy G&P, LLC in January 2007. Mr. Quinn was elected Director in March 2006 and serves as a member of the compensation committee. Mr. Quinn has been a director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Quinn is the Executive Vice President of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1998. He currently serves on the investment committee of NGP Capital Resources Company, a business development company that focuses on the energy industry.
Kenneth A. Hersh was elected Director of Eagle Rock Energy G&P, LLC in March 2006. Mr. Hersh has been a director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Hersh is the Chief Executive Officer of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds and has served in those or similar capacities since 1989. He currently serves as a director of NGP Capital Resources Company, a business development company that focuses on the energy industry. Mr. Hersh has served as a director of Energy Transfer Partners, L.L.C., the indirect general partner of Energy Transfer Partners, L.P., a natural gas gathering and processing and transportation and storage and retail propane company, since February 2004 and
has served as a director of LE GP, LLC, the general partner of Energy Transfer Equity, L.P., since October 2002.
Philip B. Smith was elected Director of Eagle Rock Energy G&P, LLC in October 2006 and serves as a member of the audit committee, the conflicts committee and the compensation committee of the board of directors of Eagle Rock Energy G&P, LLC. From April 2002 to September 2006, Mr. Smith has been administering estates and managing private investments. From January 1999 until March 2002, Mr. Smith was Chief Executive Officer and Chairman of the Board of Directors of Prize Energy Corp. in Grapevine, Texas. From 1996 until 1999, he served as a director of HS Resources, Inc. and of Pioneer Natural Resources Company and its predecessor, MESA, Inc.
John A. Weinzierl was elected Director of Eagle Rock Energy G&P, LLC in March 2006. Mr. Weinzierl has been a director of Eagle Rock Pipeline, L.P. since December 2005 and Eagle Rock Energy, Inc. from December 2003 through December 2005. Mr. Weinzierl is a managing director of the Natural Gas Partners private equity funds and has served in that capacity since 2005. Upon joining Natural Gas Partners in 1999, Mr. Weinzierl served as an associate until 2000, and as a principal until he became a managing director in December 2004. He presently serves as a director for several of Natural Gas Partners’ private portfolio companies.
William K. White was elected Director of Eagle Rock Energy G&P, LLC in October 2006 and serves as Chairman of the audit committee and as Chairman of the conflicts committee of the board of directors of Eagle Rock Energy G&P, LLC. Mr. White is President of Amado Energy Management, LLC, a position he has held since December 2002. He is also a member of the board of directors of Teton Energy Corporation. From September 1996 to November 2002, Mr. White was Vice President, Finance and Administration and Chief Financial Officer for Pure Resources, Inc. From January 1995 to July 1996, Mr. White was a Senior Vice President for TCW Asset Management Company.
Effective January 31, 2007, Joan A.W. Schnepp, formerly Executive Vice President, Secretary and director, resigned from Eagle Rock Energy G&P, LLC. Ms. Schnepp, who co-founded Eagle Rock in June 2002 left to pursue other interests.
Item 11.
Item 11.
Executive Compensation.
Reimbursement of Expenses of Our General Partner
Neither our general partner nor Eagle Rock Energy G&P, LLC receives any management fee or other compensation for its management of our partnership. Our general partner and its affiliates, including Eagle Rock Energy G&P, LLC, however, is reimbursed for all expenses incurred on our behalf, including expenses relating to the cost of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business and allocable to us. We recognize and record these expenses in our financial statements on an accrual basis and in the same period as our general partner or its affiliates incur them on our behalf.
Executive Compensation
All employees, including executive and other officers, are employed by Eagle Rock Energy G&P, LLC, as the general partner of our general partner. The compensation of the executive officers of Eagle Rock Energy G&P, LLC during 2006 was set by the compensation committee of Eagle Rock Energy G&P, LLC’s board of directors prior to our initial public offering in October 2006 and, consequently, was not designed specifically for the management of our assets or our business. The compensation committee of Eagle Rock Energy G&P, LLC is in the process of designing a comprehensive executive compensation program to provide competitive compensation opportunities that align and drive executive officer performance in support of our business strategies and attract, motivate and retain high quality talent with the skills and competencies appropriate for our business. During this process, the compensation committee of Eagle Rock Energy G&P, LLC may consult with one or more compensation consultants and review relevant market data in determining compensation levels and compensation program elements. We anticipate that our executive compensation
program will include a mix of base salary, cash awards, and equity awards fit the overall compensation objectives identified by the compensation committee of Eagle Rock Energy G&P, LLC.
Because compensation in 2006 was not designed specifically to compensate executive officers for efforts relating solely to our business as a publicly traded partnership, we believe the specific compensation information relating to our executive officers is not indicative of compensation for the executive officers under our current structure as a publicly traded partnership. Therefore, we have not reported such compensation for 2006.
Employment and Severance Agreements
At the time of his employment, Richard W. FitzGerald entered into an employment agreement with Eagle Rock Energy G&P, LLC, which provides for an annual base salary of $200,000. The agreement also entitles Mr. FitzGerald to participate in our compensation and benefit plans, and receive company-provided disability benefits and life insurance and certain other fringe benefits. Mr. FitzGerald is also eligible to participate in a company-sponsored incentive bonus plan. In addition, the agreement contains a severance provision that provides that if Mr. FitzGerald’s employment is terminated for any reason other than cause, he is entitled to a one-time severance payment in the amount of his annual base salary. As part of his employment agreement, Mr. FitzGerald has also made an investment of $50,000 in Eagle Rock Holdings, L.P. and was granted 150,000 units in Eagle Rock Holdings, L.P. that are subject to vesting restrictions. For a description of the units in Eagle Rock Holdings, L.P., see Item 13. Certain Relationships and Related Transactions and Director Independence.
We have not entered into any other employment agreements with our executive officers.
Compensation of Directors
Officers or employees of Eagle Rock Energy G&P, LLC or its affiliates who also serve as directors will not receive additional compensation for their service as a director of Eagle Rock Energy G&P, LLC. Our general partner anticipates that directors who are not officers or employees of Eagle Rock Energy G&P, LLC or its affiliates will receive compensation for serving on the board of directors and committee meetings. It is expected that such directors will receive (a) $50,000 per year as an annual retainer fee; (b) $5,000 per year for each committee of the board of directors on which such director serves; (c) 5,000 restricted common units upon becoming a director, vesting in one-third increments over a three-year period; (d) 1,000 restricted common units on each anniversary of becoming a director, vesting in one-third increments over a three-year period; (e) reimbursement for out-of-pocket expenses associated with attending meetings of the board of directors or committees; (f) reimbursement for educational costs relevant to the director’s duties; and (g) director and officer liability insurance coverage. Each director is fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth the beneficial ownership of our units as of March 26, 2007 held by:
•
each person or group of persons who then will beneficially own 5% or more of the then outstanding units;
•
each member of the board of directors of Eagle Rock Energy G&P, LLC;
•
each named executive officer of Eagle Rock Energy G&P, LLC; and
•
all directors and officers of Eagle Rock Energy G&P, LLC as a group.
*
Less than 1%
(1)
Unless otherwise indicated, the address for all beneficial owners in this table is 16701 Greenspoint Park Drive, Suite 200 Houston, Texas 77060.
(2)
Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Alex A. Bucher, Jr., Joan A. W. Schnepp, Richard W. FitzGerald, Alfredo Garcia, William E. Puckett, J. Stacy Horn and Stephen O. McNair have approximately a 31.09%, 47.94%, 7.80%, 5.15%, 0.82%, 3.69%, 0.84%, 0.60% and 0.52% limited partner interest, respectively, in Eagle Rock Holdings, L.P. Eagle Rock GP, L.L.C., which is owned 39.14%, 60.35%, 0.35% and 0.16% by Natural Gas Partners VII, L.P., Natural Gas Partners VIII, L.P., Mr. Bucher and Ms. Schnepp, respectively, owns a 1.0% general partner interest in Eagle Rock Holdings, L.P. The units held by Eagle Rock Holdings, L.P., are reported in this table as beneficially owned by Mr. Bucher, Ms. Schnepp, Mr. Garcia, Mr. Puckett, Mr. FitzGerald, Mr. McNair and Mr. Horn in proportion to their beneficial ownership in Eagle Rock Holdings, L.P., and Eagle Rock GP, L.L.C.
(3)
RR Advisors, LLC, RCH Energy MLP Fund GP, L.P., RCH Energy MLP Fund, L.P., RCH Energy MLP Fund-A, L.P., RCH Energy Opportunity Fund I GP, L.P., and RCH Energy Opportunity Fund I, L.P. all beneficially own units of Eagle Rock Energy Partners, L.P. Robert J. Raymond is the sole member of RR Advisors, LLC, which is the general partner of RCH Energy Opportunity Fund I GP, L.P., which is the
general partner of RCH Energy Opportunity Fund I, L.P., and RCH Energy MLP Fund GP, L.P., which is the general partner of RCH Energy MLP Fund, L.P., and RCH Energy MLP Fund-A, L.P. and, as sole member of each entity, Mr. Raymond holds voting and dispositive power over the units owned by each such entity.
(4)
Kenneth A. Paulo, Senior Vice President of Williams, Jones & Associates, Inc., has voting and dispositive power over the units beneficially owned by Williams, Jones & Associates, Inc.
(5)
Effective January 31, 2007, Ms. Schnepp resigned from all offices and her position as a member of the board of directors of Eagle Rock Energy G&P, LLC.
(6)
G.F.W. Energy VII, L.P., GFW VII, L.L.C., G.F.W. Energy VIII, L.P. and GFW VIII, L.L.C. may be deemed to beneficially own the units held by Eagle Rock Holdings, L.P., that are attributable to Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. by virtue of GFW VII, L.L.C. being the sole general partner of G.F.W. Energy VII, L.P. and GFW VIII, L.L.C. being the sole general partner of G.F.W. Energy VIII, L.P. Kenneth A. Hersh, who is a member of each of GFW VII, L.L.C. and GFW VIII, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition of, the units. Mr. Hersh disclaims any deemed beneficial ownership of the units held by Eagle Rock Holdings, L.P.
(7)
In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., and Eagle Rock G&P, LLC, Alex A. Bucher, Jr. also owns 5,200 units through our directed unit program. In addition to the units she holds through her ownership of Eagle Rock Holdings, L.P., and Eagle Rock G&P, LLC, Joan A.W. Schnepp also owns 500 units through our directed unit program. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., Richard W. FitzGerald also beneficially owns 5,000 units through our directed unit program, plus 10,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., William E. Puckett also beneficially owns 10,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., J. Stacy Horn also beneficially owns 1,500 units through our directed unit program plus 10,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan. In addition to the units he holds through his ownership of Eagle Rock Holdings, L.P., Stephen O. McNair also beneficially owns 500 units through our directed unit program plus 10,000 units that are subject to a three-year vesting schedule pursuant to our long-term incentive plan.
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence.
Since January 1, 2006, we have been involved in several transactions involving Holdings or affiliates of Natural Gas Partners. Holdings, which is the sole member of Eagle Rock Energy G&P, LLC, which is the general partner of our general partner, is currently owned by Natural Gas Partners (approximately 79.8%) and certain members of our management team, including Alex A. Bucher, Chief Executive Officer of G&P (approximately 7.8%), Alfredo Garcia, Senior Vice President, Corporate Development of G&P (approximately 3.7%), Richard W. FitzGerald, Senior Vice President, Chief Financial Officer and Treasurer of G&P (approximately 0.8%), William E. Puckett, Senior Vice President, Commercial Operations of G&P (approximately 0.8%), J. Stacy Horn, Senior Vice President, Commercial Development of G&P (approximately 0.6%), and Stephen O. McNair, Vice President, Operations and Technical Services of G&P (approximately 0.5%). The following members of the board of directors of G&P hold positions at Natural Gas Partners set forth next to each person’s name: William J. Quinn, Executive Vice President of NGP Energy Capital Management and a managing partner of the Natural Gas Partners private equity funds, Kenneth A. Hersh, Chief Executive Officer of NGP Energy Capital Management and is a managing partner of the Natural Gas Partners private equity funds, John A. Weinzierl, a managing director of the Natural Gas Partners private equity funds.
Holdings had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. The agreement was modified on December 1, 2005 to increase the management fee to $0.5 million annually and to a $1.0 million annual level upon the completion of our initial public offering, or IPO. We expensed the fee paid under the advisory arrangement. For the twelve months periods ended December 31, 2005 and December 31, 2006, respectively, we expensed $0.1 million and $0.4 million for the agreement
activity. At the time of the initial public offering, Holdings terminated the agreement with a $6.0 million payment to Natural Gas Partners. The termination fee was recorded as an expense during the fourth quarter 2006 with the offset to members’ equity.
During the fourth quarter 2005, Eagle Rock Pipeline, L.P., our predecessor, declared and accrued a $5.0 million distribution. This distribution was included in the balance sheet at December 31, 2005, in “distribution payable-affiliate”. In addition, for 2006, we paid $215.2 million distributions to Holdings, including its ownership in our general partner, for initial public offering related activities and earning distributions.
As discussed in Note 4 accompanying our Consolidated Financial Statements for the year ended December 31, 2006, on June 2, 2006, we acquired Midstream Gas Services, L.P., which was a portfolio company of Natural Gas Partners VII, L.P., which is an affiliate of Natural Gas Partners. As part of the consideration for the acquisition, Natural Gas Partners VII, L.P. received pre-IPO units of limited partner interest in Eagle Rock Pipeline, L.P., which were converted into our common units at the time of the initial public offering. During 2006 and separate from regular distributions relating to ownership of our common units after the initial public offering, we caused distributions to be made to Natural Gas Partners VII, L.P. for the units of $3.7 million related to initial public offering activities and earning distributions.
On July 1, 2006, we entered into a month-to-month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which our Texas Panhandle Systems has the option to sell a portion of its natural gas supply. We received a Letter of Credit related to this agreement securing the purchase of any natural gas under this agreement. We recorded $19.4 million of revenues in 2006 from this relationship.
In the fourth quarter 2006 and in connection with consummating our initial public offering, entered into an Omnibus Agreement with G&P, Holdings and our general partner, Eagle Rock Energy GP, L.P., which requires us to reimburse G&P for the payment of certain expenses incurred by G&P or its employees, officers, or representatives on our behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.
Item 14.
Item 14.
Principal Accountant Fees and Services.
The following set forth fees billed by Deloitte & Touche LLP for the audit of our annual financial statements and other services rendered for the fiscal years ended December 31, 2006, 2005 and 2004:
(1)
Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of interim financial statements, audits of businesses acquired and other customary documents filed with the Securities and Exchange Commission.
(2)
Includes fees related to consultations concerning financial accounting and reporting standards and services related to the implementation of our internal controls over financial reporting.
(3)
Includes fees related to professional services for tax compliance, tax advice, and tax planning.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-
audit services to be provided, consistent with all applicable laws, to us by our external auditors; and to establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has started a process for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Deloitte & Touch LLP, including audit services, audit-related services, tax services and other services, must be pre-approved by the Committee.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
•
the auditors’ internal quality-control procedures;
•
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
•
the independence of the external auditors;
•
the aggregate fees billed by our external auditors for each of the previous two fiscal years; and
•
the rotation of the lead partner.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements:
The following financial statements and the Report of Independent Registered Public Accounting Firm are filed as a part of this report on the pages indicated:
(a)(2) Financial Statement Schedules:
None.
(a)(3) Exhibits:
The following documents are included as exhibits to this report:
*
Filed herewith
**
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report on its behalf by the undersigned, thereunto duly authorized, on April 2, 2007.
EAGLE ROCK ENERGY PARTNERS, L.P.
By: Eagle Rock Energy GP, L.P., its general partner
By: Eagle Rock Energy G&P, LLC, its general partner
By:
/s/ Alex A. Bucher, Jr.
Name: Alex A. Bucher, Jr.
Title:
President and Chief Executive Officer
EAGLE ROCK ENERGY PARTNERS, L.P.
By: Eagle Rock Energy GP, L.P., its general partner
By: Eagle Rock Energy G&P, LLC, its general partner
By:
/s/ Richard W. FitzGerald
Name: Richard W. FitzGerald
Title:
Senior Vice President, Chief Financial Officer and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
CONSOLIDATED FINANCIAL STATEMENTS
OF EAGLE ROCK ENERGY PARTNERS, L.P.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of
Eagle Rock Energy Partners, L.P.
Houston, Texas
We have audited the consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (formerly Eagle Rock Pipeline, L.P.) (the “Partnership”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 2, 2007
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2006 AND 2005
(1)
20,691,495 and 24,150,739 units were issued and outstanding for 2006 and 2005, respectively.
(2)
20,691,495 and 0 units were issued and outstanding for 2006 and 2005, respectively.
See notes to consolidated financial statements.
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
See notes to consolidated financial statements.
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
See notes to consolidated financial statements.
EAGLE ROCK ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004
(1)
Represents adjusted common units for presentation purposes. Based upon units on formation in March 2006, adjusted for IPO unit rate conversion.
(2)
Units issued adjusted for IPO conversion.
See notes to consolidated financial statements.
EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND
NOTE 1.
ORGANIZATION AND DESCRIPTION OF BUSINESS
Eagle Rock Pipeline, L.P., a Texas limited partnership, is an indirect wholly-owned subsidiary of Eagle Rock Holdings, L.P. (“Holdings”). Holdings is a portfolio company of Irving, Texas based private equity capital firm, Natural Gas Partners. Eagle Rock Pipeline, L.P. was formed on November 14, 2005 for the purpose of owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.
In May 2006, Eagle Rock Energy Partners, L.P., a Delaware limited partnership, an indirect wholly-owned subsidiary of Holdings, was formed for the purpose of completing a public offering of common units. On October 24, 2006, it offered and sold 12,500,000 common units in its initial public offering, or IPO, at a price of $19.00 per unit. Net proceeds from the sale of the units, $222.1 million after underwriting costs, were used for reimbursement of capital expenditures for investors prior to the initial public offering, replenish working capital, and distribution arrearage payment. In connection with the initial public offering, Eagle Rock Pipeline, L.P. was merged with and into a newly formed subsidiary of Eagle Rock Energy Partners, L.P. (“Eagle Rock Energy” or the “Partnership”).
Basis of Presentation and Principles of Consolidation - The accompanying financial statements include assets, liabilities and the results of operations of Eagle Rock Energy from October 24, 2006, and the results of operations of Eagle Rock Pipeline, L.P. and its predecessor entities for the periods prior to October 24, 2006. The reorganization of these entities was accounted for as a reorganization of entities under common control. The general partner of Eagle Rock Energy and Eagle Rock Midstream Resources, L.P. is Eagle Rock Energy GP, L.P., a wholly-owned subsidiary of Holdings. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources L.P. and their subsidiaries and, effective October 24, 2006, Eagle Rock Energy Partners, L.P. are collectively referred to as “Eagle Rock Energy” or the “Partnership.”
Eagle Rock Energy, through its wholly-owned subsidiaries and partnerships, provides midstream energy services, including gathering, transportation, treating, processing and conditioning services in the Texas Panhandle region. The Partnership’s natural gas pipelines collect natural gas from designated points near producing wells and transports these volumes to third-party pipelines, the Partnership’s gas processing plants, utilities and industrial consumers. Natural gas shipped to the Partnership’s gas processing plants, either on the Partnership’s pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed into mixed natural gas liquids, or NGLs. The Partnership conducts it operation within two geographic areas of Texas. The Partnership’s Texas Panhandle assets consist of assets acquired from ONEOK, Inc. on December 1, 2005 (see Note 4), and include gathering and processing assets (the “Texas Panhandle Systems”). The Partnership’s southeast Texas and Louisiana assets include a non-operated 25% undivided interest in a processing plant as well as a non-operated 20% undivided interest in a connected gathering system. In December 2005, the Partnership began operations of a newly constructed pipeline in east Texas that connects to the non-operated system (collectively, the “Texas and Louisiana System”). This pipeline was completed on February 28, 2006. On March 31, 2006, the Partnership’s southeast Texas and Louisiana System completed the acquisition of 100% interest in the Brookeland and Masters Creek processing plants in east Texas from Duke Energy Field Services. (see Note 4) On June 2, 2006, the Partnership’s Texas Panhandle Systems completed the acquisition of 100% of Midstream Gas Services, L.P. (see Note 4)
NOTE 2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Eagle Rock Energy is the owner of a non-operating undivided interest in a gas processing plant and a gas gathering system. Eagle Rock Energy owns these interests as tenants in common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. All significant intercompany accounts and transactions are eliminated in the consolidated financial statements.
EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Use of Estimates - The preparation of the financial statements in conformity with accounting policies generally accepted in the United States of America requires management to make estimates and assumptions which affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although management believes the estimates are appropriate, actual results can differ from those estimates.
Cash and Cash Equivalents - Cash and cash equivalents include certificates of deposit or other highly liquid investments with maturities of three months or less at the time of purchase.
Concentration and Credit Risk - Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. On June 1, 2006, the Partnership increased the parties to which it was selling liquids and natural gas from two to eleven. These industry concentrations have the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that the Partnership’s customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the credit risk posed by this industry concentration is offset by the creditworthiness of the Partnership’s customer base. The Partnership’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
Certain Other Concentrations - The Partnership relies on natural gas producer customers for its natural gas and natural gas liquid supply, with two producers accounting for 29.2% of its natural gas supply in its Texas Panhandle Systems and 55.9% of its natural gas supply in the Texas and Louisiana System for the year ended December 31, 2006. Those suppliers accounted for 28.1% of the natural gas supply for the year ended December 31, 2005. While there are numerous natural gas and natural gas liquid producers and some of these producer customers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership’s results of operations and financial position could be materially adversely affected.
Property, Plant, and Equipment - Property, plant, and equipment consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, which are carried at cost less accumulated depreciation. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership calculates depreciation on the straight-line method principally over 20-year estimated useful lives of the Partnership’s newly developed or acquired assets, with usually no residual value. The weighted average useful lives are as follows:
The Partnership capitalizes interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. During the year ended December 31, 2006, the Partnership capitalized interest of $0.4 million. The Partnership capitalized interest of $10,300 related to the construction of a pipeline in 2005.
The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets or enhance its productivity or efficiency from its original design are capitalized over the expected benefit or useful period.
Impairment of Long-Lived Assets - Management evaluates whether the carrying value of long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not
EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. Management considers various factors when determining if these assets should be evaluated for impairment, including but not limited to:
•
significant adverse change in legal factors or in the business climate;
•
a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;
•
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
•
significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
•
a significant change in the market value of an asset; or
•
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.
If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third-party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.
Intangible Assets - Intangible assets consist of right-of-ways and easements and acquired customer contracts, which the Partnership amortizes over the term of the agreement or estimated useful life. Amortization expense was approximately $15.8 million for the year ended December 31, 2006, and approximately $1.2 million for the year ended December 31, 2005. There was no amortization expense for any period prior to December 1, 2005. Estimated aggregate amortization expense for each of the five succeeding years is as follows: 2007 - $16.4 million; 2008 - $16.4 million; 2009 - $16.4 million; 2010 - $16.4 million; and 2011 - $7.7 million. Intangible assets consisted of the following:
The amortization period for our rights-of-way and easements was 20 years and contracts range from 5 to 15 years, respectively, and overall, approximately 13 years average in total as of December 31, 2006. The amortization period for our rights-of-way and easements are 20 years and contracts are 5 years, respectively, and overall, approximately 12 years average in total as of December 31, 2005.
Other Assets - Other assets primarily consist of costs associated with debt issuance ($7.8 million at December 31, 2006), net of amortization. Amortization of debt issuance costs is calculated using the straight-line method over the maturity of the associated debt (or the expiration of the contract).
Transportation and Exchange Imbalances - In the course of transporting natural gas and natural gas liquids for others, the Partnership may receive for redelivery different quantities of natural gas or natural gas
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liquids than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or natural gas liquids in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2006 and 2005, the Partnership had imbalance receivables totaling $0.3 million and $0.2 million, respectively, and imbalance payables totaling $1.9 million and $0.8 million, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold.
Revenue Recognition - Eagle Rock Energy’s primary types of sales and service activities reported as operating revenue include:
•
sales of natural gas, NGLs and condensate;
•
natural gas gathering, processing and transportation, from which Eagle Rock Energy generates revenues primarily through the compression, gathering, treating, processing and transportation of natural gas; and
•
NGL transportation from which we generate revenues from transportation fees.
Revenues associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenues associated with transportation and processing fees are recognized when the service is provided.
For gathering and processing services, Eagle Rock Energy either receives fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Eagle Rock Energy is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the keep-whole contract type, Eagle Rock Energy purchases wellhead natural gas and sells processed natural gas and NGLs to third parties.
Transportation, compression and processing-related revenue are recognized in the period when the service is provided and include the Partnership’s fee-based service revenue for services such as transportation, compression and processing.
Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. The Partnership has recorded environmental liabilities of $0.3 million as of December 31, 2006 and 2005.
Income Taxes - No provision for federal income taxes related to the operation of Eagle Rock Energy is included in the accompanying consolidated financial statements as such income is taxable directly to the partners holding interests in the Partnership. The State of Texas enacted a margin tax in May 2006 which requires the Partnership to pay beginning in 2008, based on 2007 results. The method of calculation for this margin tax is similar to an income tax, requiring the Partnership to recognize currently the impact of this new tax on the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Approximately $1.2 million deferred state tax liability has been recorded at December 31, 2006. (see Note 15)
Derivatives - Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS No. 133), establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities
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in the statement of financial position and measure those instruments at fair value. SFAS No. 133 provides that normal purchase and normal sale contracts, when appropriately designated, are not subject to the statement. Normal purchases and normal sales are contracts which provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term; however, the Partnership does have certain contracts which extend through the life of the dedicated production. The Partnership uses financial instruments such as puts, swaps and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument’s fair value with changes in fair value reflected in the statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 10 for a description of the Partnership’s risk management activities.
NOTE 3.
NEW ACCOUNTING PRONOUNCEMENTS
In May 2005, the Financial Accounting Standards Board, or the FASB, issued SFAS No. 154, Accounting Changes and Error Corrections. This statement establishes new standards on the accounting for and reporting of changes in accounting principles and error corrections. This statement requires retrospective application to the financial statements of prior periods for all such changes, unless it is impracticable to do so. The Partnership adopted this statement beginning January 1, 2006. The adoption of this statement had no impact and is not expected to have a material effect on our financial position or results of operations on future financial statements.
In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155 amends SFAS No. 133, which required a derivative embedded in a host contract which does not meet the definition of a derivative be accounted for separately under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope of such exception to strips which represent rights to receive only a portion of the contractual interest cash flows or of the contractual principal cash flows of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, which permitted a qualifying special-purpose entity to hold only a passive derivative financial instrument pertaining to beneficial interests issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS No. 140 to allow a qualifying special purpose entity to hold a derivative instrument pertaining to beneficial interests that itself is a derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued (or subject to a re-measurement event) following the start of an entity’s first fiscal year beginning after September 15, 2006. The Partnership will adopt SFAS No. 155 on January 1, 2007, and does not expect this standard to have a material impact, if any, on our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosure about fair value measurements. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the effect the adoption of this statement will have, if any, on its consolidated results of operations and financial position.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, (SFAS No. 159) which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.
A significant portion of the Partnership’s sale and purchase arrangements are accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements which establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location at the same or at another specified date. These arrangements are detailed either jointly, in a single contract or separately, in individual contracts which are entered into concurrently or in contemplation of one another with a single or multiple counterparties. Both transactions require physical delivery of the natural gas and the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk. In accordance with the provision of Emerging Issues Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty (“EITF 04-13”), the Partnership reflects the amounts of revenues and purchases for these transactions as a net amount in its consolidated statements of operations beginning with April 2006. For the year ended December 31, 2006, the Partnership did not enter into any purchase and sale agreements with the same counterparty. As a result, the adoption of EITF 04-13 had no effect on the results of operations for the year ended December 31, 2006.
In October 2005, the FASB issued Staff Position FAS 13-1 concerning the accounting for rental expenses associated with operating leases for land or buildings which are incurred during a construction period. We considered how this might apply to our payment for rights-of-way associated with the construction of pipelines, and we do not anticipate any changes to our accounting practices or impacts on our results of operations or financial condition in light of this recently issued Staff Position.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions, as defined. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. We do not expect that the adoption of FIN 48 will have a material impact on our results of operations or financial position.
NOTE 4.
ACQUISITIONS
On December 1, 2005, the Partnership completed its acquisition of ONEOK Field Services Texas (“ONEOK Texas”) for $531.1 million (the “Panhandle Acquisition”) to expand the Partnership’s asset base and to obtain critical mass. ONEOK Texas provides natural gas midstream services in the Texas Panhandle and its assets primarily consist of gathering pipelines and processing plants. The results of operations have been included in the statement of operations since the date of acquisition. The Partnership financed the Panhandle Acquisition and related transactions and costs with proceeds from the following:
Borrowings of approximately $393.5 million of the $400.0 million initially borrowed under the new Credit Facility discussed in Note 6;
Net proceeds received from Holdings from a $133.0 million private placement of equity to Natural Gas Partners.
With the assistance of a third-party valuation firm, management has prepared an assessment of the fair value of the property, plant and equipment and intangible assets of the Panhandle Acquisition as of December 1, 2005. The purchase price allocation was finalized during the fourth quarter 2006. The purchase price has been allocated as presented below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
All liabilities assumed were at their fair values. The fair value of intangibles is estimated to be $115.5 million. There were no identified intangibles which were determined to have indefinite lives.
On March 31, 2006, the Partnership’s southeast Texas and Louisiana System completed the acquisition of an 80% interest in the Brookeland gathering and processing facility, a 76.3% interest in the Masters Creek gathering system and 100% of the Jasper NGL line for $75.7 million to solidify the Partnership’s southeast Texas and Louisiana operations and to integrate with the segments existing operations. The Partnership commenced recording these results of operations on April 1, 2006. On April 7, 2006, the remaining interests were acquired for $20.2 million and the results of operations have been recorded effective as of April 1, 2006, as results of operations for the period April 1, 2006 to April 7, 2006, were not material. Included in other assets at December 31, 2005 is $7.6 million of escrow cash on deposit for the acquisition of these assets. This escrow cash was released on March 31, 2006. The purchase price was allocated on a preliminary basis to property, plant and equipment and intangibles in the amounts of $88.8 million and $7.9 million, respectively, based on their respective fair value as determined by management with the assistance of a third-party valuation specialist. In addition to long-term assets, the Partnership assumed certain accrued liabilities. The purchase price has been allocated as presented below.
On June 2, 2006, the Partnership purchased Midstream Gas Services, L.P. (“MGS”) for $4.7 million in cash and 809,174 (1,125,416 pre-IPO conversion) in common units to integrate with the Texas Panhandle Systems’ existing operations. The Partnership will issue up to 798,113 common units, converted at the time of the initial public offering (1-for-0.719), to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a contingent earn-out payment if MGS achieves certain financial objectives for the year ending December 31, 2007. The Partnership commenced recording the results of operations on June 2, 2006.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following pro forma information for the year ended December 31, 2006 and 2005, assumes the Brookeland gathering and processing facility, the Masters Creek gathering system, the Jasper NGL line and the MGS interests (only for 2006) had been acquired on January 1, 2006 and 2005, respectively (unaudited):
In July 2004, the Partnership acquired a 25% undivided interest in a processing plant as well as a 20% undivided interest in a connected gathering system for $19.9 million. The results of operations have been recorded on a pro-rata consolidation basis and have been included in the statement of operations since the date of acquisition.
NOTE 5.
FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS
Fixed assets consisted of the following:
Depreciation expense for the years ended December 31, 2006 and 2005 were $27.4 million and $2.9 million, respectively.
Asset Retirement Obligations - On December 31, 2005, we adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (FIN 47). FIN 47 clarified that the term “conditional asset retirement obligation”, as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within our control. Although uncertainty about the timing and/or method of settlement may exist and may be
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, we are required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The adoption of FIN 47 had no impact on the Partnership’s consolidated financial statements.
A reconciliation of our liability for asset retirement obligations is as follows:
Asset retirement obligations prior to January 1, 2005 were not significant.
NOTE 6.
LONG-TERM DEBT
Long-term debt consists of:
On August 31, 2006, the Partnership amended and restated its existing credit agreement (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement is a $500.0 million credit agreement with a syndicate of commercial and investment banks and institutional lenders, with Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and Restated Credit Agreement provides for $300.0 million aggregate principal amount of Series B Term Loans (the “Term Loan”) and up to $200.0 million aggregate principal amount of Revolving Commitments (the “Revolver”). A $750,000 principal payment was made toward the Term Loan in October 2006, reducing the Term Loan aggregate principal amount to $299.3 million. The Amended and Restated Credit Agreement includes a sub limit for the issuance of standby letters of credit for the aggregate unused amount of the Revolver. At December 31, 2006, the Partnership had $2.5 million of outstanding letters of credit. In addition, the loan agreement allows the Partnership to expand its credit facility by an additional $100.0 million if the Partnership meets certain financial conditions.
In connection with the Amended and Restated Credit Agreement, the Partnership incurred debt issuance costs of $2.4 million to the Consolidated Statement of Operations during the year ended December 31, 2006, of which approximately $0.4 million was expensed directly, with the remaining portion to be amortized over the remaining term of the agreement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Prior to the initial public offering, the principal amount due under the Term Loan was to be repaid in consecutive quarterly installments on the four quarterly scheduled interest payment dates applicable to the Term Loan, commencing September 30, 2006, in an amount equal to one-quarter percent (0.25%) of the original principal amount outstanding with the remaining outstanding principal amount due on the Term Loan maturity date. With the consummation of the Partnership’s initial public offering on October 27, 2006, quarterly installments under the Term Loan ceased with the balance due on the Term Loan maturity date, August 31, 2011. The Revolver matures on the revolving commitment termination date, August 31, 2011.
In certain instances defined in the Amended and Restated Credit Agreement, the Term Loan is subject to mandatory repayments and the Revolver is subject to a commitment reduction for cumulative asset sales exceeding $15.0 million; insurance/condemnation proceeds; the issuance of equity securities; and the issuance of debt.
The Amended and Restated Credit Agreement contains various covenants which limit the Partnership’s ability to grant certain liens; make certain loans and investments; make certain capital expenditures outside the Partnership’s current lines of business or certain related lines of business; make distributions other than from available cash; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Partnership’s assets. Additionally, the Amended and Restated Credit Agreement limits the Partnership’s ability to incur additional indebtedness with certain exceptions and purchase money indebtedness and indebtedness related to capital or synthetic leases not to exceed $7.5 million.
The Amended and Restated Credit Agreement also contains covenants, which, among other things, require the Partnership, on a consolidated basis, to maintain specified ratios or conditions as follows:
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Adjusted EBITDA (as defined) to interest expense of not less than 2.0 to 1.0 through December 31, 2006, and 2.50 to 1.0 thereafter; and
•
Total consolidated funded debt to Adjusted EBITDA (as defined) of not more than 6.0 to 1.0 through December 31, 2006, and 5.0 to 1.0 thereafter and 5.25 to 1.0 for the three quarters following a material acquisition;
Based upon the senior debt to Adjusted EBITDA ratio calculated as of December 31, 2006 (utilizing the September and December 2006 quarters Consolidated Adjusted EBITDA as defined under the Credit Agreement annualized for an annual Adjusted EBITDA amount for the ratio), the Partnership has approximately $80.0 million of unused capacity under the Amended and Restated Credit Agreement Revolver with $24.0 million available capacity at year end.
At the Partnership’s election, the Term Loan and the Revolver bear interest on the unpaid principal amount either at a base rate plus the applicable margin (defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the Adjusted Eurodollar Rate plus the applicable margin (defined as 2.25% per annum, reducing to 2.00% when consolidated funded debt to Adjusted EBITDA (as defined) is less than 3.5 to 1). At August 31, 2006, the Partnership elected the Eurodollar Rate plus the applicable margin (defined as 2.25%) for a cumulative rate of 7.65%. The applicable margin increased by 0.50% per annum on January 31, 2007, under the Amended and Restated Credit Agreement as the Partnership elected not to obtain a rating by S&P and Moody’s.
Base rate interest loans are paid the last day of each March, June, September and December. Eurodollar Rate Loans are paid the last day of each interest period, representing one-, two-, three- or six-, nine- or twelve-months, as selected by the Partnership. Interest on the Term Loan is paid approximately each December 31, March 31, June 30 and September 30 of each year, commencing on September 30, 2006. The Partnership pays a commitment fee equal to (1) the average of the daily difference between (a) the revolver commitments and (b) the sum of the aggregate principal amount of all outstanding revolver loans plus the aggregate principal amount of all outstanding swing loans times (2) 0.50% per annum; provided, the commitment fee percentage increased by 0.25% per annum on January 31, 2007, as the Partnership elected not to obtain a rating by S&P and Moody’s. The Partnership also pays a letter of credit fee equal to (1) the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
applicable margin for revolving loans which are Eurodollar Rate loans times (2) the average aggregate daily maximum amount available to be drawn under all such Letters of Credit (regardless of whether any conditions for drawing could then be met and determined as of the close of business on any date of determination). Additionally, the Partnership pays a fronting fee equal to 0.125%, per annum, times the average aggregate daily maximum amount available to be drawn under all letters of credit.
The obligations under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of the Partnership’s assets, including a pledge of all of the capital stock of each of its subsidiaries.
Prior to entering into the Amended and Restated Credit Agreement, the Partnership operated under a $475.0 million credit agreement (the “Credit Agreement”) with a syndicate of commercial banks, including Goldman Sachs Credit Partners L.P., as the administrative agent. The Credit Agreement was entered into on December 1, 2005. The Credit Agreement provided for $400.0 million aggregate principal amount of Series A Term Loans (the “Original Term Loan”) and up to $75.0 million ($100.0 million effective June 2, 2006) aggregate principal amount of Revolving Commitments (the “Original Revolver”). The Credit Agreement included a sub limit for the issuance of standby letters of credit for the lesser of $55.0 million or the aggregate unused amount of the Original Revolver. At December 31, 2005, the Partnership had $400.0 million outstanding under the Original Term Loan, $7.6 million outstanding under the Original Revolver and $0.1 million of outstanding letters of credit.
Scheduled maturities of long-term debt as of December 31, 2006, were as follows:
The Partnership was in compliance with the financial covenants under the Amended and Restated Credit Agreement as of December 31, 2006. If an event of default existed under the Amended and Restated Credit Agreement, the lenders would be able to accelerate the maturity of the Amended and Restated Credit Agreement and exercise other rights and remedies.
NOTE 7.
MEMBERS’ EQUITY
At December 31, 2005, the Partnership had common units outstanding representing 98.01% of limited partnership interest and 1.99% of general partner interests, all of which were controlled by Holdings. On March 27, 2006, the Partnership sold 5,455,050 common units in a private placement for $98.3 million and converted the 98.01% limited partnership interest into 33,582,918 subordinated units. In June 2006, the Partnership issued 1,125,416 common units in connection with the MGS acquisition. At the initial public offering, the pre-IPO common units outstanding were converted into publicly traded common units using a factor of approximately 0.7191. Additionally, Holdings contributed $0.2 million in cash during 2006. For the initial public offering, the Partnership issued 12.5 million common units. The overallotment option was exercised by the underwriters in November 2006 with 1,463,785 common units being issued from common units acquired by the Partnership from Holdings and selected private investors. The exercise of the overallotment did not result in additional shares being issued by the Partnership. At December 31, 2006, there were 20,691,496 common units and 20,691,496 subordinated units (all subordinated units owned by Holdings) outstanding. In addition, there were 122,450 restricted unvested common units outstanding.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Additionally, during the fourth quarter of 2006, Holdings paid $6.0 million to terminate the advisory fee arrangement with Natural Gas Partners. The expense was recorded on the Partnership’s financial results of operations with the offset to members’ equity (see Note 8).
Subordinated units represent limited liability interests in the Partnership, and holders of subordinated units exercise the rights and privileges available to unitholders under the limited liability company agreement. Subordinated units, during the subordination period, will generally receive quarterly cash distributions only when the common units have received a minimum quarterly distribution of $0.3625 per unit. Subordinated units will convert into common units on a one-for-one basis when the subordination period ends. Pursuant to the Partnership’s agreement of limited partnership, the subordination period will extend to the earliest date following March 31, 2009 for which there does not exist any cumulative common unit arrearage.
On August 15, 2006, the Partnership declared and paid a distribution of $1.9 million to its common unit holders. As of September 30, 2006, the Partnership was in arrears on its subordinated units and general partner units in the amount of $10.7 million and $0.3 million, respectively for the second quarter of 2006. The arrearages were declared and paid at the time of the initial public offering. The IPO net cash received was $222.1 million, including $3.0 million for initial public offering transaction costs reimbursement to the Partnership. Distributions of $219.1 million were made in the fourth quarter for capital expenditure and working capital reimbursements and distribution arrearages. On November 14, 2006, the Partnership distributed $14.4 million from its third quarter 2006 results. This distribution was made to the unitholders on record as of September 30, 2006. In November, the Partnership received net cash of $26.0 million for the exercise of the overallotment by the underwriters. This amount was used to buy common units from Holdings and certain Pre-IPO investors.
On January 26, 2006, the Partnership declared its 2006 fourth quarter distribution to its common unitholders of record as of February 7, 2007. The distribution amount per common unit was $0.3625 which was adjusted to $0.2679 per unit for the partial quarter the units were outstanding due to the initial public offering date. The distribution was made on February 15, 2007. No distributions were declared on the general partner or subordinated units.
NOTE 8.
RELATED PARTY TRANSACTIONS
Holdings had a management advisory arrangement with Natural Gas Partners requiring a quarterly fee payment. The agreement was modified on December 1, 2005, to increase the management fee to $0.5 million annually, with an escalation to $1.0 million annually, upon the completion of the initial public offering by the Partnership. The fee paid under the advisory arrangement has been expensed by the Partnership. For years ended 2006 and 2005, the Partnership expensed the $0.4 million and $0.1 million for the management advisory arrangement. At the time of the initial public offering, Holdings terminated the agreement with a $6.0 million payment to Natural Gas Partners. The termination fee was recorded as an expense of the Partnership during the fourth quarter of 2006, with the offset as a capital contribution.
During the fourth quarter of 2005, the Partnership declared and accrued a $5.0 million distribution. This distribution was included in the balance sheet at December 31, 2005, in distribution payable-affiliate. In addition, for 2006, the Partnership paid a $215.2 million distribution to Holdings, for initial public offering related activities and earning distributions. A portion of this amount was distributed to Holdings from the Partnership’s distributions to its general partner. Holdings owns and controls the general partner of the partnership while Holdings is controlled by Natural Gas Partners with minority ownership by certain management personnel and board members of the Partnership’s general partner.
As discussed in Note 4, on June 2, 2006, the Partnership acquired Midstream Gas Services, L.P., which was a portfolio company of Natural Gas Partners in its Natural Gas Partners Vll, L.P. As part of the consideration for the acquisition, Natural Gas Partners received pre-initial public offering common units in the Partnership which were converted at the time of the initial public offering. During 2006, the Partnership made
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
distributions of $3.7 million to Natural Gas Partners for these units for the initial public offering, overallotment and other distribution activities.
On July 1, 2006, the Partnership entered into a month to month contract for the sale of natural gas with an affiliate of Natural Gas Partners, under which the Partnership’s Texas Panhandle Systems has the option to sell a portion of its gas supply. The Partnership has received a Letter of Credit related to this agreement. The Partnership recorded $19.4 million of revenues in 2006 from the agreement, of which there was a receivable of $2.7 million outstanding at December 31, 2006.
In the fourth quarter of 2006, the Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P, LLC, Holdings and the Partnership’s general partner which requires the Partnership to reimburse Eagle Rock Energy G&P, LLC for the payment of certain expenses incurred on the Partnership’s behalf, including payroll, benefits, insurance and other operating expenses, and provides certain indemnification obligations.
The Partnership does not directly employ any persons to manage or operate our business. Those functions are provided by our general partner. We reimburse the general partner for all direct and indirect costs of these services.
NOTE 9.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. As of December 31, 2006, the debt associated with the Credit Agreement bore interest at floating rates. As such, carrying amounts of this debt instruments approximates fair value.
NOTE 10.
RISK MANAGEMENT ACTIVITIES
The Credit Agreement required the Partnership to enter into interest rate risk management activities. In December 2005, the Partnership entered into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into this swap is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments for a period of five years from January 1, 2006 to January 1, 2011. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense. The table below summarizes the terms, amounts received or paid and the fair values of the various interest swaps:
For the year ended December 31, 2006, the Partnership recorded a fair value gain within interest expense of $2.8 million (unrealized) and a $0.5 million realized gain. As of December 31, 2006, the fair value liability of these contracts totaled $1.2 million.
The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors which are beyond the Partnership’s control. In order to manage the risks associated with natural gas and NGLs, the Partnership engages in risk management activities that take the form of commodity derivative instruments. Currently these activities are governed by the general partner, which today typically prohibits speculative transactions and limits the type, maturity and notional
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
amounts of derivative transactions. We will be implementing a Risk Management Policy which will allow management to execute crude oil, natural gas liquids and natural gas hedging instruments in order to reduce exposure to substantial adverse changes in the prices of these commodities. We intend to monitor and ensure compliance with this Risk Management Policy through senior level executives in our operations, finance and legal departments.
In October and December 2005, the Partnership entered into the following:
•
Over-the-counter NGL puts, costless collar and swap transactions for the sale of Mont Belvieu gas liquids with a combined notional amount of 530,000 Bbls per month for a term from January 2006 through December 2010;
•
Condensate puts and costless collar transactions for the sale of West Texas Intermediate crude oil with a combined notional amount of 250,000 Bbls per month for a term from January 2006 through December 2010; and
•
Natural gas calls for the sale of Henry Hub natural gas with a notional amount of 200,000 MMBtu per month for a term from January 2006 through December 2007.
During 2006, the Partnership entered into the following additional risk management activities:
•
Costless collar transactions for West Texas Intermediate crude oil with a combined notional amount of 50,000 Bbls per month for a term of October through December 2006; and, 60,000 Bbls per month for a term of January 2007 through December 2007.
•
Fixed swap agreements to hedge WTS-WTI basis differential in amount of 20,000 Bbls per month for a term of October-December 2006; and, 20,000 Bbls per month for a term of January through December 2007.
•
Natural gas fixed swap agreements to hedge short natural gas positions with a combined notional amount of 100,000 MMBtu per month for the term of August 2006 through September 2006.
The counterparties used for these transactions have investment grade ratings. The NGL and condensate derivatives are intended to hedge the risk of weakening NGL and condensate prices with offsetting increases in the value of the puts based on the correlation between NGL prices and crude oil prices. The natural gas derivatives are included to hedge the risk of increasing natural gas prices with the offsetting value of the natural gas calls.
Eagle Rock Energy has not designated these derivative instruments as hedges and as a result is marking these derivative contracts to market with changes in fair values recorded as an adjustment to the mark-to-market gains /losses on risk management transactions within revenue. For the year ended December 31, 2005, the Partnership recorded a fair value gain of $7.3 million related to these contracts. As of December 31, 2005, the fair value of these contracts totaled $34.8 million. For the year ended December 31, 2006, the Partnership recorded a loss on risk management instruments of $24.0 million, representing a fair value (unrealized) loss of $7.1 million, amortization of put premiums of $19.2 million and net (realized) settlements gain to the Partnership of $2.3 million. As of December 31, 2006, the fair value of these contracts, including the put premiums, totaled $8.4 million.
NOTE 11.
COMMITMENTS AND CONTINGENT LIABILITIES
Litigation - The Partnership is subject to several lawsuits, primarily related to the payments of liquids and gas proceeds in accordance with contractual terms. The Partnership has accruals of $1.5 million as of December 31, 2006 and $1.63 million, as of December 31, 2005, related to these matters. In addition, the Partnership is also subject to other lawsuits related to the payment of liquid and gas proceeds in accordance with contractual terms for which the Partnership has been indemnified up to a certain dollar amount. For the indemnified lawsuits, the Partnership has not established any accruals as the likelihood of these suits being successful against them is considered remote. If there ultimately is a finding against the Partnership in the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
indemnified cases, the Partnership could make a claim against the indemnification up to limits of the indemnification. These matters are not expected to have a material adverse effect on our financial position, results of operations or cash flows.
Insurance - Eagle Rock Energy carries insurance coverage which includes the assets and operations, which management believes is consistent with companies engaged in similar commercial operations with similar type properties. These insurance coverages includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Eagle Rock Energy field operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business interruption/extra expense, and (5) corporate liability policies including Directors and Officers coverage and Employment Practice liability coverage. All coverages are subject to certain deductibles, terms, and conditions common for companies with similar types of operation.
Eagle Rock Energy also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.
Regulatory Compliance - In the ordinary course of business, the Partnership is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position of the Partnership.
Environmental - The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership’s combined results of operations, financial position or cash flows. At December 31, 2006 and 2005, the Partnership had accrued $0.3 million for environmental matters.
Other Commitments and Contingencies - The Partnership utilizes assets under operating leases for its corporate office, certain rights-of way and facilities locations, vehicles and in several areas of its operation. Rental expense, including leases with no continuing commitment, amounted to $0.2 million, $0.2 million, and $37,000 for the years ended December 31, 2006, 2005 and 2004, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2006, commitments under long-term non-cancelable operating leases for the next five years and thereafter are payable as follows: 2007 - $0.7 million; 2008 - $0.7 million; 2009 - $0.7 million; 2010 - $0.3 million; 2011 - $0.3 million; and thereafter - $2.0 million.
NOTE 12.
SEGMENTS
Based on the Partnership’s approach to managing its assets, the Partnership believes its operations consist of two geographic segments and one functional (corporate) segment: (i) gathering, processing, transportation and marketing of natural gas in the Texas Panhandle Systems, (ii) gathering, natural gas processing and related
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NGL transportation in the Texas and Louisiana System, and (iii) risk management and other corporate activities. The Partnership’s chief operating decision-maker currently reviews its operations using these segments. The Partnership evaluates segment performance based on segment margin before depreciation and amortization. Transactions between reportable segments are conducted on a basis believed to be at market values. Prior to the December 1, 2005, acquisition of the Panhandle Acquisition, the Partnership had only one segment.
Summarized financial information concerning the Partnership’s reportable segments is shown in the following table:
(a)
Represents results of our derivatives activity.
(b)
Segment profit (loss) is defined as sales to external customers minus cost of natural gas and natural gas liquids and other cost of sales. Sales to external customers for the corporate column include the impact of the risk management activities.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table reconciles segment profit (loss) to income from continuing operations:
NOTE 13.
DISCONTINUED OPERATIONS
On July 1, 2004, the Partnership closed on the sale of its Dry Trail assets for $37.4 million. The Dry Trail assets consisted of a CO2 tertiary recovery plant near Hough, Oklahoma. The Dry Trail assets had revenues of $5.1 million in 2004, and generated income of $2.7 million, which is net of interest expense allocated to these operations of $0.3 million in 2004. All interest incurred during the period the Partnership owned the Dry Trail assets was allocated to discontinued operations as the debt was specifically related to those assets and was paid off with proceeds from the sale. The Partnership realized a gain of $19.5 million in 2004 on the sale.
NOTE 14.
EMPLOYEE BENEFIT PLAN
In 2004, the Partnership began providing a defined contribution benefit plan to its employees who have been with the Partnership longer than six months. The plan provides for a dollar for dollar matching contribution by the Partnership of up to 3% of an employee’s contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership contributes 6% of a participating employee’s base salary annually, contributed at 3% twice a year. Expenses under the plan for the years ended December 31, 2006, 2005 and 2004 were approximately $0.3 million, $37,000 and $65,000, respectively.
NOTE 15.
INCOME TAXES
In May 2006, the State of Texas enacted a margin tax which will become effective in 2008. This margin tax will require the Partnership to determine a tax of 1.0% on our “margin,” as defined in the law, beginning in 2008 based on our 2007 results. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes less the cost of the products sold for federal income tax purposes, in the State of Texas. Under the provisions of Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”, the Partnership is required to record the effects on deferred taxes for a change in tax rates or tax law in the period which includes the enactment date.
Under FAS 109, taxes based on income like the Texas margin tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Temporary differences related to the Partnership’s property will affect the Texas margin tax, and we have recorded a deferred tax liability in the amount of $1.2 million as of December 31, 2006.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 16.
EQUITY-BASED COMPENSATION
On October 24, 2006, the general partner for Eagle Rock Energy Partners, L.P., approved a long-term incentive plan (LTIP for its employees, directors and consultants who provide services to the Partnership covering an aggregate of 1,000,000 common unit options, restricted units and phantom units. With the consummation of the initial public offering on October 24, 2006, 124,450 restricted common units were issued to the employees and directors of the General Partner who provide services to the Partnership. The awards generally vest on the basis of one third of the award each year. During the restriction period, distribution associated with the granted awards will be held by the Partnership and will be distributed to the awardees upon the restriction lapsing. No options or phantom units have been issued to date.
A summary of the restricted common units activity for the year ended December 31, 2006, is provided below:
For the fourth quarter of 2006, compensation expense of $0.1 million was recorded related to the granted restricted units.
As of December 31, 2006, unrecognized compensation costs related to the outstanding restricted units under our LTIP totaled $2.2 million. The granted restricted units were valued at the market price of the initial public offering less a discount for the delayed in their cash distributions during the unvested period. The remaining expense is to be recognized over a weighted average of 2.75 years.
NOTE 17.
EARNINGS PER UNIT
Basic earnings per unit is computed by dividing the net income, or loss, by the weighted average number of units outstanding during a period. To determine net income, or loss, allocated to each class of ownership (common, subordinated and general partner), we first allocated net income, or loss, by the amount of distributions made for the quarter by each class, if any. The remaining net income, or loss, after the deduction for the related quarter distribution was allocated to each class in proportion to the class’ weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period. To determine the weighted average number of units outstanding for a period, we converted units existing during 2006, prior to the initial public offering, at the initial public offering conversion rate (1-for-0.7139), resulting in equivalent units for all periods. For 2005 and 2004 unit determinations, we used the initial public offering converted common and general partner units at the beginning of 2006 as the adjusted weighted average units for these earlier periods. General partner units were outstanding for this calculation as of December 1, 2005, which is the timing of the Texas Panhandle acquisition and an organization formation. There were no previous stated units during these periods. Net income for 2005 and 2004 was allocated to the common and general partner based upon the adjusted weighted average units determined above for each class.
We issued restricted, unvested common units at the time of the initial public offering, October 24, 2006. These units will be considered in the diluted common unit weighted average number in periods of net income. In periods of net losses, such as the fourth quarter and total year 2006, the units are excluded from the diluted earnings per unit calculation due to their antidilutive effect.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
At December 31, 2006, we had 20,691,495 common units, 20,691,495 subordinated units and 844,551 general partner units outstanding. In addition, we had 122,450 restricted unvested common units granted and outstanding.
The following table presents our calculation of basic earnings per unit for the periods indicated:
NOTE 18.
SUBSEQUENT EVENTS
On February 7, 2007, the Partnership declared a $0.3625 distribution per common unit for the fourth quarter of 2006, prorated to $0.2679 per common unit for the timing of the initial public offering on October 24, 2006. The distribution to the common units was paid on February 15, 2007. No distribution was made to the subordinated or general partners for the quarter.
On April 2, 2007, the Partnership announced it has signed a definitive purchase agreement to acquire Laser Midstream Energy, L.P. and certain of its subsidiaries for $136.8 million, including $110.0 million in cash and 1,407,895 of common units of the Partnership. The assets subject to this transaction include gathering systems and related compression and processing facilities in South Texas, East Texas and North Louisiana. The acquisition is subject to customary closing conditions and is expected to close in late April.
In addition, Eagle Rock announced that it has signed a definitive agreement to acquire certain fee minerals, royalties and working interest properties from Montierra Minerals & Production, L.P. (a Natural Gas Partners VII, L.P. portfolio company) and NGP-VII Income Co-Investment Opportunities, L.P. (a Natural Gas Partners affiliate) for an aggregate purchase price of $127.6 million, subject to price adjustments. Montierra and such co-investment fund (collectively, “Montierra”) will receive as consideration a total of 6,400,000 EROC common units and $6.0 million in cash. The assets conveyed in this transaction include minerals acres, and interests in wells with net proved producing reserves of approximately 4.6 billion cubic feet of gas (unaudited) and 2.5 million barrels of oil (unaudited).
The Partnership also announced on April 2, 2007, it had entered into a unit purchase agreement to sell in a private placement 7,005,495 common units to third-party investors, for total cash proceeds of $127.5 million. The Partnership also has agreed to file a registration statement with the SEC registering for resale the common units within 90 days after the closing. The proceeds from this equity private placement will fully fund the cash portion of the purchase price of the Laser acquisition. The Partnership anticipates that the private placement will close simultaneously with the Laser acquisition.
In addition, the Partnership has received $100 million in additional commitments to increase its revolver facility under its existing Amended and Restated Credit Facility. The increase of the revolver provides the Partnership with approximately $175 million in borrowing availability.
* * * *
Index to Exhibits
*
Filed herewith
**
Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment.