UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended December 31, 2005
Commission file number: 000-51120
Hiland Partners, LP
(Exact name of Registrant as specified in its charter)
DELAWARE | 71-0972724 |
(State or other jurisdiction of | (I.R.S. Employer |
incorporation or organization) | Identification No.) |
205 West Maple, Suite 1100 | |
Enid, Oklahoma | 73701 |
(Address of principal executive offices) | (Zip code) |
Registrant’s telephone number including area code (580) 242-6040
Securities registered pursuant to Section 12(b) of the Act:
None.
Securities registered pursuant to Section 12(g) of the Act:
Common limited partner units
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | | Accelerated filer o | | Non-accelerated filer x |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $81 million on June 30, 2005 based on the last sales price as quoted on the Nasdaq National Market.
At March 9, 2006, there were 4,397,633 common units and 4,080,000 subordinated units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
PART I
Items 1. and 2. Business and Properties
Our Formation and Public Offerings
Hiland Partners, LP is a Delaware limited partnership formed in October 2004 to own and operate the assets that have historically been owned and operated by Continental Gas, Inc. and Hiland Partners, LLC. In connection with our initial public offering described below, the former owners of Continental Gas and Hiland Partners, LLC and certain of our affiliates, including our general partner, contributed to us all of the assets and operations of Continental Gas, Inc., other than a portion of its working capital assets, and substantially all of the assets and operations of Hiland Partners, LLC, other than a portion of its working capital assets and the assets related to the Bakken gathering system described below, in exchange for an aggregate of 720,000 common units and 4,080,000 subordinated units, a 2% general partner interest in us and all of our incentive distribution rights, which entitle the general partner to increasing percentages of the cash we distribute in excess of $0.495 per unit per quarter.
Continental Gas, Inc. historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland gathering system. Prior to July 21, 2004, Continental Gas, Inc. was owned by Continental Resources, Inc., an independent exploration and production company owned by Harold Hamm, the Chairman of the Board of Directors of our general partner and the Harold Hamm DST and the Harold Hamm HJ Trusts, which are trusts established for the benefit of Harold Hamm’s children and which we refer to herein as the “Hamm Trusts.” On July 21, 2004, Continental Resources, Inc. completed the transfer of Continental Gas, Inc. to Harold Hamm and the Hamm Trusts. Hiland Partners, LLC historically owned our Worland gathering system, our compression services assets and the Bakken gathering system. Hiland Partners, LLC is owned by the Hamm Trusts and an entity owned by Randy Moeder, the President and Chief Executive Officer and a director of our general partner.
On February 15, 2005, we closed our initial public offering of 2,300,000 common units, which included a 300,000 unit over-allotment option that was exercised by the underwriters. Total proceeds from the sale of the units were $48.1 million, net of $3.6 million of underwriting commissions.
We completed a secondary public offering on November 21, 2005, whereby we issued 1,630,000 common units, which included 30,000 over-allotment units, at an offering price of $41.77 per common unit. Proceeds, including our general partner’s contribution of $1.4 million to maintain its 2.0% interest in us, totaled $66.1 million, net of the underwriter discount of $3.4 million. Offering costs incurred amounted to $0.6 million. We used $65.2 million of the procceds to repay a portion of credit facility borrowings we had previously used to purchase all of the outstanding membership interests in Hiland Partners, LLC, the principal asset of which is the Bakken gathering system. We refer to this acquisition as the Bakken acquisition.
References in this annual report on Form 10-K to “Hiland Partners,” “we,” “our,” “us” or similar terms refer to Hiland Partners, LP and its operating subsidiaries after giving effect to the formation transactions described above.
Overview
We are a growth oriented midstream energy partnership engaged in gathering, compressing, dehydrating, treating, processing and marketing natural gas, and fractionating, or separating, natural gas liquids, or NGLs. We also provide air compression and water injection services to an oil and gas exploration and production company for use in its oil and gas secondary recovery operations. Our operations are primarily located in the Mid-Continent and Rocky Mountain regions of the United States. In our midstream segment, we connect the wells of natural gas producers in our market areas to our gathering systems, treat natural gas to remove impurities, process natural gas for the removal of NGLs,
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fractionate NGLs into NGL products and provide an aggregate supply of natural gas and NGL products to a variety of natural gas transmission pipelines and markets. In our compression segment, we provide compressed air and water to Continental Resources, Inc., an exploration and production company wholly owned by affiliates of our general partner. Continental Resources uses the compressed air and water in its oil and gas secondary recovery operations in North Dakota by injecting them into its oil and gas reservoirs to increase oil and gas production from those reservoirs. This increased production of natural gas flows through our midstream systems.
Our midstream assets consist of eight natural gas gathering systems with approximately 1,144 miles of gas gathering pipelines, five natural gas processing plants, three natural gas treating facilities and three NGL fractionation facilities. Our compression assets consist of two air compression facilities and a water injection plant.
We commenced our midstream operations in 1990 when Continental Gas, Inc., then a subsidiary of Continental Resources, constructed the Eagle Chief gathering system in northwest Oklahoma. Since 1990, we have grown through a combination of building gas gathering and processing assets in areas where Continental Resources has active exploration and production assets and through acquisitions of existing systems, which we have then expanded. Since inception, we have constructed 325 miles of natural gas gathering pipelines, three natural gas processing plants, two treating facilities and one fractionation facility. In addition, our management team designed and constructed the Bakken gathering system that we recently acquired from an affiliate of our general partner, which currently consists of 273 miles of gas gathering pipeline, a natural gas processing plant, two compressor stations and one fractionation facility. From prior acquisitions we have also acquired 546 miles of natural gas gathering pipelines, one natural gas processing plant, one treating facility and one fractionation facility. Our total segment margin for the years ended December 31, 2005 and 2004 was $33.5 million and $15.8 million, respectively. Please read “—Non-GAAP Financial Measures” for an explanation of total segment margin and a reconciliation of total segment margin to its most directly comparable financial measure calculated and presented in accordance with generally accepted accounting principles, or GAAP.
Recent Developments
Officer Election. On March 20, 2006, Robert Shain was elected as our Vice President Northern Region Operations and Engineering. Mr. Shain has spent 30 years in the oil and natural gas industry with a focus in midstream natural gas gathering, compression, processing and treating, along with business development and marketing. He has spent the majority of his career serving in a variety of commercial roles for Impact Energy, LLC, CMS Oil Field Services, LLC, Heritage Gas Services, LLC and most recently served as Vice President of Operations and Engineering for Seminole Gas Company, LLC located in Tulsa, Oklahoma.
Expansion Projects. On February 1, 2006, we entered into a five-year definitive purchase agreement with a current producer to build additional compression facilities and to expand our existing Badlands gas gathering system into South Dakota. The Badlands gathering project, which is targeted for completion in the second quarter of 2006, is expected to cost approximately $3.0 million. We also intend to construct a 25 million cubic feet per day natural gas processing facility along our existing Matli gas gathering system. This facility will process the existing gas supply on our Matli system and will provide additional plant processing capacity for increased system volumes. The Matli expansion project, which is targeted for completion in the third quarter of 2006, is expected to cost approximately $2.8 million. We expect to fund both of the expansion projects using our existing bank credit facility.
Distribution Increase. On January 24, 2006, we declared a cash distribution of $0.625 per unit, or $2.50 per unit on an annualized basis, on our common and subordinated units for the quarter ended December 31, 2005. The distribution was paid on February 14, 2006 to unitholders of record on
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February 4, 2006. This distribution represented an increase of 22% from our distribution of $0.5125 per unit for the third quarter of 2005. Under our partnership agreement, generally our general partner is entitled to 15% of the amount we distribute to each unitholder in excess of $0.495 per unit per quarter up to $0.5625 per unit per quarter, 25% of the amount we distribute to each unitholder in excess of $0.5625 per unit per quarter up to $0.675 per unit per quarter and 50% of the excess over $0.675 per unit per quarter.
Officer Election. On January 5, 2006, Ron Hill was elected as our Vice President of Business Development. Mr. Hill has spent 29 years in the oil and natural gas industry with a 25-year focus in gas processing, midstream gas gathering, transportation and NGL marketing. He has spent the majority of his career serving in a variety of commercial roles for Tipperary Corporation, Union Texas Petroleum, Western Gas Resources, Inc. and most recently served as Vice President of Gas Supply for Pioneer Gas Pipeline, Inc. located in San Angelo, Texas.
Follow-on Offering. We completed a secondary public offering on November 21, 2005 whereby we issued 1,630,000 common units, which included 30,000 over-allotment units, at an offering price of $41.77 per common unit. Proceeds, including our general partner’s contribution of $1.4 million to maintain its 2.0% interest in us, totaled $66.1 million, net of the underwriter discount of $3.4 million. Offering costs incurred amounted to $0.6 million. We used $65.2 million of the procceds to repay a portion of credit facility borrowings we had previously used to fund the Bakken acquisition.
Badlands Expansion Project. On November 8, 2005, we entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources’ secondary oil recovery operations, in the areas specified by the contract. In return, we will receive 50% of the proceeds attributable to residue gas and natural gas liquids sales as well as certain fixed fees associated with gathering and treating the natural gas, including a $0.60 per Mcf fee for the first 36 Bcf of natural gas gathered. The board of directors, as well as the conflicts committee of the board of directors of our general partner, has approved the agreement.
In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the fourth quarter of 2006, is expected to cost approximately $40 million, which we intend to fund using our existing bank credit facility. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system.
Board Member Selections. On October 3, 2005, we announced that the board of directors of our general partner had appointed Shelby E. Odell as director. Mr. Odell was named to the audit committee and to the conflicts committee of the board of directors. On May 11, 2005, we announced that the board of directors of our general partner had appointed Rayford T. Reid as a director. Mr. Reid was also named to the compensation committee of the board of directors. For a more complete description of the board of directors of our general partner, please read “Management—Directors and Executive Officers of Hiland Partners GP, LLC.”
Bakken Acquisition. Effective September 1, 2005, we consummated the Bakken acquisition pursuant to which we acquired the outstanding membership interests in Hiland Partners, LLC, an Oklahoma limited liability company, for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. Hiland Partners, LLC’s principal asset is the Bakken gathering system located in eastern Montana. Pursuant to an option contained in the omnibus agreement we entered into with Hiland Partners, LLC and Harold Hamm and his affiliates in connection with our initial public offering, Hiland Partners, LLC granted us an exclusive two-year option to purchase the
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Bakken gathering system at fair market value at the time of purchase. A mutually-agreed-upon investment banking firm determined the fair market value of the Bakken gathering system, and the conflicts committee of the board of directors of our general partner, consisting of its independent directors, approved the transaction.
The Bakken gathering system is located in an area where a number of exploration and production companies are actively developing crude oil and associated natural gas reserves from the Bakken shale formation. As of December 31, 2005, the Bakken gathering system consisted of approximately 273 miles of gas gathering pipeline, a natural gas processing plant, two compressor stations, which are comprised of four units with an aggregate of approximately 5,884 horsepower, and one fractionation facility. The Bakken processing plant and a portion of the gathering system became operational on November 8, 2004. The gathering system has an initial capacity of approximately 25,000 Mcf/d.
Bank Credit Facility. To facilitate the closing of the Bakken acquisition, we amended our senior revolving credit facility to increase our borrowing capacity under the facility from $55.0 million to $125.0 million, consisting of a $117.5 million acquisition facility and a $7.5 million working capital facility. We used $93.7 million of this increased capacity to fund the Bakken acquisition. For a more complete description of our credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility.”
Midstream Segment
Our midstream operations consist of the following:
· gathering and compressing natural gas to facilitate its transportation to our processing plants, third party pipelines, utilities and other consumers;
· dehydrating natural gas to remove water from the natural gas stream to meet pipeline quality specifications;
· treating natural gas to remove or reduce impurities such as carbon dioxide, hydrogen sulfide and other contaminants to ensure that the natural gas meets pipeline quality specifications;
· processing natural gas to extract NGLs and selling the resulting residue natural gas and, in most cases, the NGLs; and
· fractionating a portion of our NGLs into a mix of NGL products, including ethane, propane and a mixture of butane and natural gasoline, and selling these NGL products to third parties.
Our midstream assets include the following:
· Eagle Chief Gathering System. The Eagle Chief gathering system is a 557-mile gas gathering system located in northwest Oklahoma that gathers, compresses, dehydrates and processes natural gas. The system includes the Eagle Chief processing plant and four compressor stations. We constructed the Eagle Chief gathering system in 1990 and constructed the Eagle Chief processing plant in 1995. We acquired the Carmen gathering system in August 2003, which consists solely of gathering lines to expand our Eagle Chief gathering system. Our Eagle Chief gathering system has a capacity of 30,000 Mcf/d and average throughput was approximately 20,885 Mcf/d for the year ended December 31, 2005. The system represented approximately 28.1% of our total segment margin for the year ended December 31, 2005.
· Bakken Gathering System. The Bakken gathering system is a 273-mile gas gathering system located in Richland County, Montana that gathers, compresses, dehydrates and processes natural gas. This system includes the Bakken processing plant, two compressor stations and one fractionation facility. We acquired the Bakken gathering system and the Bakken processing plant in September 2005. Our
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Bakken gathering system has capacity of 25,000 Mcf/d and average throughput was approximately 13,956 Mcf/d for the period from September 1, 2005 through December 31, 2005. The system represented approximately 19.8% of our total segment margin for the year ended December 31, 2005.
· Worland Gathering System. The Worland gathering system is a 151-mile gas gathering system located in central Wyoming that gathers, compresses, dehydrates, treats and processes natural gas, and fractionates NGLs. The system includes the Worland processing plant, four compressor stations, one treating facility and one fractionation facility. The Worland gathering system and the Worland processing plant were contributed to us on February 15, 2005 in connection with our formation and our initial public offering. Our Worland gathering system has a capacity of 8,000 Mcf/d and average throughput was approximately 3,159 Mcf/d for the period from February 15, 2005 through December 31, 2005. The system represented approximately 14.7% of our total segment margin for the year ended December 31, 2005.
· Badlands Gathering System. The Badlands gathering system is a 108-mile gas gathering system located in southwest North Dakota that gathers, compresses, dehydrates, treats and processes natural gas, and fractionates NGLs. The system includes the Badlands processing plant, four compressor stations, one treating facility and one fractionation facility. We constructed the Badlands gathering system and the Badlands processing plant in 1997. Our Badlands gathering system has a capacity of 5,000 Mcf/d and average throughput was approximately 3,055 Mcf/d for the year ended December 31, 2005. The system represented approximately 16.6% of our total segment margin for the year ended December 31, 2005.
· Matli Gathering System. The Matli gathering system is a 37-mile gas gathering system located in central Oklahoma that gathers, compresses, dehydrates, treats and processes natural gas. The system includes the Matli processing plant, two compressor stations and one treating facility. We constructed the Matli gathering system in 1999 and constructed the Matli processing plant in 2003. Our Matli gathering system has a capacity of 20,000 Mcf/d and average throughput was approximately 14,991 Mcf/d for the year ended December 31, 2005. The system represented approximately 6.1% of our total segment margin for the year ended December 31, 2005.
· Other Systems. We also own three natural gas gathering systems located in Texas, Mississippi and Oklahoma. These systems represented approximately 2.1% of our total segment margin for the year ended December 31, 2005.
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The table set forth below contains certain information regarding our gathering systems as of or for the year ended December 31, 2005.
| | | | | | Approximate | | Throughput | | Average | | Utilization | |
| | | | Length | | Wells | | Capacity | | Throughput | | of | |
Asset | | | | Type | | (Miles) | | Connected | | (Mcf/d) | | (Mcf/d) | | Capacity | |
Eagle Chief gathering system | | Gathering pipelines | | | 557 | | | | 376 | | | | 30,000 | | | | 20,850 | | | | 69.5 | % | |
| | Processing plant | | | — | | | | — | | | | 25,000 | | | | 20,850 | | | | 83.4 | % | |
Bakken gathering system | | Gathering pipelines | | | 273 | | | | 143 | | | | 25,000 | | | | 13,956 | | | | 55.8 | % | |
| | Processing plant | | | — | | | | — | | | | 25,000 | | | | 13,956 | | | | 55.8 | % | |
| | Fractionation
facility (Bbls/d) | | | — | | | | — | | | | 4,600 | | | | 2,513 | | | | 54.6 | % | |
Worland gathering system | | Gathering pipelines | | | 151 | | | | 94 | | | | 8,000 | | | | 3,159 | | | | 40.3 | % | |
| | Processing plant | | | — | | | | — | | | | 8,000 | | | | 3,159 | | | | 40.3 | % | |
| | Treating facility | | | — | | | | — | | | | 8,000 | | | | 3,159 | | | | 40.3 | % | |
| | Fractionation
facility (Bbls/d) | | | — | | | | — | | | | 650 | | | | 361 | | | | 55.5 | % | |
Badlands gathering system | | Gathering pipelines | | | 108 | | | | 96 | | | | 5,000 | | | | 3,055 | | | | 61.1 | % | |
| | Processing plant | | | — | | | | — | | | | 5,000 | | | | 3,055 | | | | 61.1 | % | |
| | Treating facility | | | — | | | | — | | | | 7,100 | | | | 3,055 | | | | 43.0 | % | |
| | Fractionation
facility (Bbls/d) | | | — | | | | — | | | | 600 | | | | 374 | | | | 62.3 | % | |
Matli gathering system | | Gathering pipelines | | | 37 | | | | 40 | | | | 20,000 | | | | 14,991 | | | | 75.0 | % | |
| | Processing plant | | | — | | | | — | | | | 10,000 | | | | 5,536 | | | | 55.4 | % | |
| | Treating facility | | | — | | | | — | | | | 10,000 | | | | 9,700 | | | | 97.0 | % | |
Other Systems | | Gathering pipelines | | | 18 | | | | 29 | | | | 7000 | | | | 4,404 | | | | 62.9 | % | |
| | Total | | | 1,144 | | | | 778 | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Compression Segment
We provide air and water compression services to Continental Resources, Inc. for use in its oil and gas secondary recovery operations under a four-year, fixed-fee contract (which we entered into in connection with our initial public offering) at our Cedar Hills compression facility, our Horse Creek compression facility and our water injection plant located next to our Cedar Hills compression facility. These assets are located in North Dakota in close proximity to our Badlands gathering system. At the compression facilities, we compress air to pressures in excess of 4,000 pounds per square inch, and at the water injection plant, we pump water to pressures in excess of 2,000 pounds per square inch. The air and water are delivered at the tailgate of our facilities into pipelines operated by Continental Resources and are ultimately utilized by Continental Resources in its oil and gas secondary operations. The natural gas produced by Continental Resources flows through our Badlands gathering system. Our compression segment represented approximately 12.6% of our total segment margin for the year ended December 31, 2005.
Competitive Strengths
Based on the following competitive strengths, we believe that we are well positioned to compete in our operating regions:
· We have expertise in developing midstream systems. Since our inception in 1990, our management has demonstrated the ability to identify midstream opportunities and build or acquire the assets needed to capitalize on those opportunities. To date, we have built or acquired eight gas gathering systems. A majority of our growth has come from gas gathering systems and plants that we have
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constructed, including the Eagle Chief, Bakken, Badlands and Matli gathering systems. Since building the Eagle Chief gathering system, we have expanded that system by constructing 180 miles of gathering pipeline and acquiring approximately 377 miles of gathering pipeline in five separate transactions. We have also utilized acquisitions such as our purchase of the 151-mile Worland gathering system in 2000 as a way to establish a presence in new areas.
· Substantially all of our facilities are modern. We built our Eagle Chief processing plant in 1995, our Badlands processing plant in 1997 and our Matli processing plant in 2003. In addition, the previous owner replaced a substantial portion of the equipment on our Worland gathering system, including the Worland processing plant, the treating facility and the fractionation facility, in 1997. Our Bakken gathering system was constructed in 2004. The condition of our facilities directly benefits our margins and our ability to attract new supplies of natural gas by offering operational efficiency and reliability. Our facilities generally require less maintenance and are subject to fewer environmental liabilities and permitting issues than older facilities.
· Our assets are strategically located in major natural gas supply areas and have available capacity. Our assets are strategically located in the Mid-Continent and Rocky Mountain regions of the United States. These regions are generally characterized by significant current drilling activity, which provides us with attractive opportunities to access newly developed natural gas supplies. Several of these regions are experiencing increased levels of exploration, development and production activities as a result of recent high commodity prices, new discoveries and the implementation of secondary recovery techniques. In addition, substantially all of our assets have available capacity. We believe that our presence in these regions, together with the available capacity of our assets and limited competitive alternatives, provides us with a competitive advantage in capturing new supplies of natural gas.
· We provide an integrated and comprehensive package of midstream services. We provide a broad range of midstream services to natural gas producers, including natural gas gathering, compression, dehydration, treating, processing and marketing and the fractionation of NGLs. We believe our ability to provide all of these services gives us an advantage in competing for new supplies of natural gas because we can provide all of the services producers, marketers and others require to connect their natural gas quickly and efficiently.
· We have the financial flexibility to pursue growth projects. Our $125.0 million bank credit facility contains a $117.5 million revolving facility for acquisitions and capital expenditures, of which approximately $83.7 million is available as of December 31, 2005, and a $7.5 million working capital facility. We believe the available capacity under our 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.
· We have significant experience operating our assets and a knowledgeable senior management team. Our senior management team has been actively involved in the construction and development of substantially all of our primary assets. Our senior management team has an average of 25 years of energy industry experience.
Business Strategies
Our management team is committed to increasing the amount of cash available for distribution per unit by executing the following strategies:
· Engaging in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or
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increased demand for our midstream services. These projects include expansion of existing systems and construction of new facilities, such as our Badlands expansion project.
· Pursuing complementary acquisitions. We intend to make complementary acquisitions of midstream assets in our operating areas that provide opportunities to expand or increase the utilization of our existing assets. We intend to pursue acquisitions that we believe will allow us to capitalize on our existing infrastructure, personnel, and producer and customer relationships to provide an integrated package of services. In addition, we may pursue selected acquisitions in new geographic areas to the extent they present growth opportunities similar to those we are pursuing in our existing areas of operations.
· Increasing volumes on our existing assets. Our gathering systems have excess capacity, which provides us with opportunities to increase throughput volume with minimal incremental costs and thereby increase cash flow. We intend to aggressively market our services to producers in order to connect new supplies of natural gas, increase volumes and more fully utilize our capacity, particularly in our areas experiencing an increased level of natural gas exploration, development and production activities.
· Taking measures that reduce our exposure to commodity price risk. Because of the significant volatility of natural gas and NGL prices, we attempt to operate our business in a manner that allows us to mitigate the impact of fluctuations in commodity prices. In order to reduce our exposure to commodity price risk, we intend to pursue fee-based arrangements, where market conditions permit, and to enter into forward sales contracts or hedging arrangements to cover a portion of our operations that are not conducted under fee-based arrangements. In addition, when processing margins (or the difference between NGL sales prices and the cost of natural gas) are unfavorable, we can elect not to process natural gas at our Eagle Chief processing plant and deliver the unprocessed natural gas directly into the interstate pipeline. Collectively, these strategies should contribute to more stable cash flows.
Midstream Assets
Our natural gas gathering systems include approximately 1,144 miles of pipeline. A substantial majority of our revenues are derived from gathering, compressing, dehydrating, treating, processing and marketing the natural gas that flows through our gathering pipelines and from fractionating NGLs resulting from the processing of natural gas into NGL products. We describe our principal systems below.
Eagle Chief Gathering System
General. The Eagle Chief gathering system is located in northwest Oklahoma and consists of approximately 557 miles of natural gas gathering pipelines, ranging from two inches to 16 inches in diameter, and the Eagle Chief processing plant. The gathering system has a capacity of approximately 30,000 Mcf/d and average throughput was approximately 20,850 Mcf/d for the year ended December 31, 2005. There are four gas compressor stations located within the gathering system, comprised of nine units with an aggregate of approximately 7,875 horsepower.
We completed construction and commenced operation of the Eagle Chief gathering system in 1990 and constructed the Eagle Chief processing plant in 1995. Since its construction, we have expanded the size of the Eagle Chief gathering system through the acquisition of approximately 377 miles of gathering pipelines in five separate acquisitions, including our acquisition of the Carmen gathering system, and the construction of approximately 180 miles of gathering pipelines.
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The Eagle Chief processing plant processes natural gas that flows through the Eagle Chief gathering system to produce residue gas and NGLs. The natural gas gathered in this system is lean gas that is not required to be processed to meet pipeline quality specifications when we sell into interstate markets. The plant has processing capacity of approximately 25,000 Mcf/d. During the year ended December 31, 2005, the facility processed approximately 20,850 Mcf/d of natural gas and produced approximately 756 Bbls/d of NGLs.
Natural Gas Supply. As of December 31, 2005, 376 wells were connected to our Eagle Chief gathering system. These wells are located in the Anadarko Basin of northwestern Oklahoma and generally have long lives with predictable steady flow rates. The primary suppliers of natural gas to the Eagle Chief gathering system are Chesapeake Operating and Continental Resources, which represented approximately 65.1% and 12.2%, respectively, of the Eagle Chief gathering system’s natural gas supply for the year ended December 31, 2005.
The natural gas supplied to the Eagle Chief gathering system is generally dedicated to us under individually negotiated long-term contracts. Some of our contracts have an initial term of five years.
Following the initial term, these contracts generally continue on a year to year basis unless terminated by one of the producers. In addition, some of our contracts are for the life of the lease. Natural gas is purchased at the wellhead from the producers under percentage-of-proceeds contracts, percent-of-index contracts or fee-based contracts. For the year ended December 31, 2005, approximately 48.0%, 46.9% and 5.1% of our total segment margin attributable to the Eagle Chief gathering system was derived from percentage-of-proceeds, percent-of-index and fee-based contracts, respectively. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Our Natural Gas Purchase Contracts.”
Our Eagle Chief gathering system is located in an active drilling area. Recently, this area has experienced increased levels of natural gas exploration, development and production activities as a result of recent high natural gas prices, new discoveries and the implementation of new exploration and production techniques. For example, our average throughput at the Eagle Chief gathering system increased from 16,900 Mcf/d for December 2003 to 20,850 Mcf/d for December 2005. During the year ended December 31, 2005, we added 31 wells to our system. We believe that this higher level of exploration and development activity in this area will continue and that many of the producers drilling in the area will choose to use our midstream natural gas services due to our excess capacity in this system and limited competitive alternatives.
Markets for Sale of Natural Gas and NGLs. The Eagle Chief gathering system has numerous market outlets for the natural gas that we gather and NGLs that we produce on the system. The residue gas is sold at the tailgate of the Eagle Chief processing plant on the Oklahoma Gas Transportation pipeline to intrastate markets and on the Panhandle Eastern Pipeline Company pipeline to interstate markets. Because the area connected to our Eagle Chief gathering system produces lean natural gas, we are able to bypass our Eagle Chief processing plant by selling into the interstate markets when processing margins are unfavorable. The NGLs extracted from the gas at the Eagle Chief processing plant are transported by pipeline to ONEOK Hydrocarbon Company’s Medford facility for fractionation. We are currently selling the NGLs to ONEOK Hydrocarbon under a year to year contract.
Our primary purchasers of residue gas and NGLs on the Eagle Chief gathering system were Tenaska Marketing Ventures, BP Energy Company and OGE Energy Resources, Inc., which represented approximately 25.8%, 21.4% and 17.3%, respectively, of the revenues from such sales for the year ended December 31, 2005.
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Bakken Gathering System
General. The Bakken gathering system is located in eastern Montana and consists of approximately 273 miles of natural gas gathering pipelines, ranging from three inches to twelve inches in diameter, the Bakken processing plant and a fractionation facility. The gathering system has a capacity of approximately 25,000 Mcf/d and average throughput was approximately 13,956 Mcf/d for the period from September 1, 2005 through December 31, 2005. There are two gas compressor stations located within the gathering system, comprised of four units with an aggregate of approximately 5,884 horsepower.
We acquired the Bakken gathering system in September 2005 in connection with our acquisition of Hiland Partners, LLC. The Bakken gathering system, including the Bakken processing plant, was constructed during 2004 and commenced operations on November 8, 2004.
The Bakken processing plant processes natural gas that flows through the Bakken gathering system to produce residue gas and NGLs. The plant has processing capacity of approximately 25,000 Mcf/d. For the period from September 1, 2005 through December 31, 2005, the facility processed approximately 13,956 Mcf/d of natural gas and produced approximately 1,668 Bbls/d of NGLs.
The Bakken gathering system also includes a fractionation facility that separates NGLs into propane and a mixture of butane and gasoline. The fractionation facility has a capacity to fractionate approximately 4,600 Bbls/d of NGLs. For the period from September 1, 2005 through December 31, 2005, the facility fractionated an average of approximately 2,513 Bbls/d to produce approximately 915 Bbls/d of propane and approximately 726 Bbls/d of a mixture of butane and gasoline.
Natural Gas Supply. As of December 31, 2005, 143 wells were connected to our Bakken gathering system. These wells, which are located in the Williston Basin of Montana, primarily produce crude oil from the Bakken formation. The associated natural gas produced from these wells flows through our Bakken gathering system. The primary suppliers of natural gas to the Bakken gathering system are Enerplus Resources (USA) Corporation, Continental Resources and Burlington Resources Trading, Inc., which represented approximately 48.8%, 36.2% and 13.2%, respectively, of the Bakken gathering system’s natural gas supply for the period from September 1, 2005 through December 31, 2005.
Substantially all of the natural gas supplied to the Bakken gathering system is dedicated to us under three individually negotiated percentage-of-proceeds contracts. Two of these contracts have an initial term of ten years and one is for the life of the lease. Under these contracts, natural gas is purchased at the wellhead from the producers. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Our Natural Gas Purchase Contracts.”
Our Bakken gathering system is located in an active drilling area. For example, during the period from September 1, 2005 through December 31, 2005, we added 20 wells to our system. From the period from January 1, 2005 through August 30, 2005 the previous owner added 86 wells to the system. We believe that this higher level of exploration and development activity in this area will continue and that many of the producers drilling in the area will choose to use our midstream natural gas services due to our excess capacity in this system and limited competitive alternatives.
Markets for Sale of Natural Gas and NGLs. Residue gas derived from our processing operations is sold at the tailgate of the Bakken processing plant on the Williston Basin Intrastate Pipeline to intrastate markets. We sell the propane that is produced by our fractionation facility and the remaining NGL products to various end-users at the tailgate of the plant.
Our primary purchasers of residue gas and NGLs on the Bakken gathering system were SemStream, L.P., Montana-Dakota Utilities Company and Tenaska Marketing Ventures, which represented
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approximately 38.7%, 33.6% and 27.7% respectively, of the revenues from such sales for the period from September 1, 2005 through December 31, 2005.
Worland Gathering System
General. The Worland gathering system is located in central Wyoming and consists of approximately 151 miles of natural gas gathering pipelines, ranging from two inches to eight inches in diameter, the Worland processing plant, a natural gas treating facility and a fractionation facility. The gathering system has a capacity of approximately 8,000 Mcf/d and average throughput was approximately 3,159 Mcf/d for the period from February 15, 2005 through December 31, 2005. There are four gas compressor stations located within the gathering system, comprised of six units with an aggregate of approximately 2,200 horsepower.
The Worland gathering system and the Worland processing plant were contributed to us on February 15, 2005 in connection with our formation and our initial public offering. This gathering system, including the Worland processing plant, was originally built in the mid 1980s. A substantial portion of the equipment on the Worland gathering system, including the Worland processing plant, the treating facility and the fractionation facility, was replaced in 1997.
The Worland processing plant processes natural gas that flows through the Worland gathering system to produce residue gas and NGLs. The natural gas gathered in this system is rich gas that must be processed in order to meet pipeline quality specifications. The plant has processing capacity of approximately 8,000 Mcf/d. During the period from February 15, 2005 through December 31, 2005, the facility processed approximately 3,159 Mcf/d of natural gas and produced approximately 176 Bbls/d of NGLs.
The Worland gathering system includes a natural gas amine treating facility that removes carbon dioxide and hydrogen sulfide from natural gas that is gathered into our system before the natural gas is introduced to transportation pipelines to ensure that it meets pipeline quality specifications. Generally, the natural gas gathered in this system contains a high concentration of hydrogen sulfide, a highly toxic and corrosive chemical that must be removed prior to transporting the gas via pipeline. Our Worland treating facility has a circulation capacity of 70 gallons per minute and throughput capacity of 8,000 Mcf/d.
The Worland gathering system also includes a fractionation facility that separates NGLs into propane and a mixture of butane and gasoline. The fractionation facility has a capacity to fractionate approximately 650 Bbls/d of NGLs. For the period from February 15, 2005 through December 31, 2005, the facility fractionated an average of approximately 361 Bbls/d to produce approximately 65 Bbls/d of propane and approximately 67 Bbls/d of a mixture of butane and gasoline.
Natural Gas Supply. As of December 31, 2005, 94 wells were connected to our Worland gathering system. These wells are located in the Bighorn Basin of central Wyoming and generally have long lives with predictable and steady flow rates. The primary suppliers of natural gas to the Worland gathering system are Continental Resources and KCS Resources, Inc., which represented approximately 62.1% and 27.7%, respectively, of the Worland gathering system’s natural gas supply for the period from February 15, 2005 through December 31, 2005.
The natural gas supplied to the Worland gathering system is generally dedicated to us under individually negotiated long-term contracts. The initial term of such agreements is generally ten years with five years remaining on most of the contracts. Following the initial term, these contracts generally continue on a year to year basis, unless terminated by one of the producers. Natural gas is purchased at the wellhead from the producers under percent-of-index contracts and fixed price contracts. For the period from February 15, 2005 through December 31, 2005, approximately 94.6% and 5.4% of our total segment margin attributable to the Worland gathering system was derived from percent-of-index contracts and fixed priced contracts, respectively. For a more complete discussion of our natural gas purchase contracts,
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please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Our Natural Gas Purchase Contracts.”
Markets for Sale of Natural Gas and NGLs. Residue gas derived from our processing operations is sold at the tailgate of the Worland processing plant on the Williston Basin Intrastate Pipeline to intrastate markets. We sell the propane that is produced by our fractionation facility and the remaining NGL products to various end-users at the tailgate of the plant.
Our primary purchasers of residue gas and NGLs on the Worland gathering system were Rainbow Gas Company and a subsidiary of Kinder Morgan Energy Partners, L.P., which represented approximately 63.4% and 21.9%, respectively, of revenues from such sales on the Worland gathering system for the period from February 15, 2005 through December 31, 2005.
Badlands Gathering System and Air Compression and Water Injection Facilities
General. The Badlands gathering system is located in southwestern North Dakota and consists of approximately 108 miles of natural gas gathering pipelines, ranging from two inches to eight inches in diameter, the Badlands processing plant, a natural gas treating facility and a fractionation facility. The gathering system has a capacity of approximately 5,000 Mcf/d and average throughput was approximately 3,055 Mcf/d for the year ended December 31, 2005. There are four gas compressor stations located within the gathering system, comprised of four units with an aggregate of approximately 1,128 horsepower.
We completed construction and commenced operation of the Badlands gathering system, including the Badlands processing plant, in 1997. The Badlands processing plant processes natural gas that flows through the Badlands gathering system to produce residue gas and NGLs. The natural gas gathered in this system is rich gas that must be processed in order to meet pipelines quality specifications. The plant has processing capacity of approximately 5,000 Mcf/d. During the year ended December 31, 2005, the facility processed approximately 3,055 Mcf/d of natural gas and produced approximately 349 Bbls/d of NGLs.
The Badlands gathering system includes a natural gas treating facility that uses a solid chemical to remove hydrogen sulfide from natural gas that is gathered into our system before the natural gas is introduced to transportation pipelines to ensure it meets pipeline quality specifications. Our Badlands treating facility has throughput capacity of 7,100 Mcf/d.
The Badlands gathering system also includes a fractionation facility that separates NGLs into propane and a mixture of butane and gasoline. The fractionation facility has a capacity to fractionate approximately 600 Bbls/d of NGLs. For the year ended December 31, 2005, the facility fractionated an average of approximately 374 Bbls/d of to produce approximately 111 Bbls/d of propane and approximately 151 Bbls/d of a mixture of butane and gasoline.
On February 1, 2006, we entered into a five-year definitive purchase agreement with a current producer to build additional compression facilities and to expand our existing gas gathering system into South Dakota. The gathering project, which is targeted for completion in the second quarter of 2006, is expected to cost approximately $3.0 million, which we intend to fund using our existing bank credit facility.
On November 8, 2005, we entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources’ secondary oil recovery operations, in the areas specified by the contract. In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the 4th quarter of 2006, is expected to cost approximately $40 million, which we intend to
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fund using our existing bank credit facility. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system.
Natural Gas Supply. As of December 31, 2005, 96 wells were connected to our Badlands gathering system. These wells are located in the Williston Basin of southwestern North Dakota and generally have long lives with predictable and steady flow rates. The primary suppliers of natural gas to the Badlands gathering system are Continental Resources, Luff Exploration Company and Burlington Resources, which represented approximately 58.4%, 23.2% and 13.6%, respectively, of the Badlands gathering system’s natural gas supply for the year ended December 31, 2005.
The natural gas supplied to the Badlands gathering system is generally dedicated to us under individually negotiated long-term contracts. Our new agreement with Continental Resources has an initial term of 15 years. Under this agreement, we will receive 50% of the proceeds attributable to residue gas and natural gas liquids sales as well as certain fixed fees associated with gathering and treating the natural gas, including a $0.60 per Mcf fee for the first 36 Bcf of natural gas gathered. This agreement will replace our existing agreement with Continental Resources in the area when the new plant becomes operational. The initial term of our other agreements in this area is generally ten years with five years remaining on most of the contracts. Following the initial term, these contracts generally continue on a year to year basis, unless terminated by one of the producers. For these other agreements, natural gas is purchased at the wellhead from the producers under percentage-of-index arrangements. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Our Natural Gas Purchase Contracts.”
Air Compression and Water Injection Facilities. We believe that our Badlands gathering system is strategically located in an area where secondary recovery operations may provide us with additional natural gas supplies. In order to enhance the production of natural gas that flows through out Badlands gathering system, we currently provide air compression and water injection services to Continental Resources under long-term contracts at our Cedar Hills compression facility, our Horse Creek compression facility and our water injection Plant, all of which are located in North Dakota in close proximity to our Badlands gathering system. For a description of these services, please read “Compression Assets.”
Markets for Sale of Natural Gas and NGLs. Residue gas derived from our processing operations is sold at the tailgate of the Badlands processing plant to end-users or on an interstate pipeline located at the tailgate of the plant. We sell the propane that is produced by our fractionation facility and the remaining NGL products to various end-users at the tailgate of the plant.
Our primary purchasers of the residue gas, propane and NGLs from the Badlands gathering system were Continental Resources, a subsidiary of Kinder Morgan Energy Partners, L.P. and a subsidiary of Plains All American Pipeline, L.P., which represented approximately 38.2%, 24.1% and 18.2%, respectively, of the revenues from such sales for the year ended December 31, 2005.
Matli Gathering System
General. The Matli Gathering System is located in central Oklahoma and consists of approximately 37 miles of natural gas gathering pipelines, ranging from three inches to 12 inches in diameter, the Matli processing plant and a natural gas treating facility. The gathering system has a capacity of approximately 20,000 Mcf/d and average throughput was approximately 14,991 Mcf/d for the year ended December 31, 2005. There are two gas compressor stations located within the gathering system, comprised of six units with an aggregate of approximately 5,746 horsepower.
We completed construction and commenced operation of the Matli gathering system in 1999 and constructed the Matli processing plant in 2003. The Matli processing plant processes natural gas on the
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Matli gathering system to produce residue gas and NGLs. The natural gas gathered in this system must be processed in order to meet pipeline quality specifications, but is relatively lean gas. The plant has processing capacity of approximately 10,000 Mcf/d. During the year ended December 31, 2005, the facility processed approximately 5,536 Mcf/d of natural gas and produced approximately 160 Bbls/d of NGLs.
The Matli gathering system includes a natural gas treating facility that uses a liquid chemical to remove hydrogen sulfide from natural gas that is gathered into our system before the natural gas is introduced to transportation pipelines to ensure it meets pipeline quality specifications. Our Matli treating facility has throughput capacity of 10,000 Mcf/d. During the year ended December 31, 2005, the facility treated approximately 9,700 Mcf/d of natural gas.
We intend to construct a 25 million cubic feet per day natural gas processing facility along our existing gas gathering system. This facility will process the existing gas supply on our system and will provide additional plant processing capacity for increased system volumes. The expansion project, which is targeted for completion in the third quarter of 2006, is expected to cost approximately $2.8 million, which we intend to fund using our existing bank credit facility.
Natural Gas Supply. As of December 31, 2005, 40 wells were connected to our Matli gathering system. These wells are located in the Anadarko Basin of central Oklahoma and generally have long lives with predictable and steady flow rates. The primary suppliers of natural gas to the Matli gathering system are Continental Resources and Range Resources Corporation, which represented approximately 48.9% and 40.9%, respectively, of the Matli gathering system’s natural gas supply for the year ended December 31, 2005.
The Matli gathering system is located in an active drilling area. The natural gas supplied to the Matli gathering system is generally dedicated to us under individually negotiated long-term contracts. The initial term of such agreements is generally ten years with five years remaining on most of the contracts. Following the initial term, these contracts generally continue on a year to year basis, unless terminated by one of the producers. Natural gas is purchased at the wellhead from the producers under fee-based contracts. For a more complete discussion of our natural gas purchase contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Our Natural Gas Purchase Contracts.”
Markets for Sale of Natural Gas and NGLs. Residue gas resulting from our processing operations is sold at the tailgate of the plant on the Oklahoma Gas Transportation intrastate pipeline. The NGLs produced at the Matli processing plant are currently transported by truck to the ONEOK Hydrocarbon Medford facility for fractionation. As part of our $2.8 million expansion project mentioned above, we intend to convert an existing natural gas pipeline into a NGL pipeline to transport NGLs to the ONEOK Hydrocarbon Medford facility.
Our primary purchasers of residue gas and NGLs on the Matli gathering system were OGE Energy Resources, Tenaska Marketing Ventures and BP Energy, which represented approximately 35.4%, 35.0% and 19.3%, respectively, of the revenues from such sales for the year ended December 31, 2005.
Other Systems
In addition to the midstream assets described above, we own two gathering systems located in Texas and Mississippi and a gathering pipeline system in Oklahoma. These assets do not provide us with material cash flows and consist of the following:
· Driscoll Gathering System. Our Driscoll gathering system is located in south Texas and consists of approximately four miles of natural gas gathering pipeline and a compressor station.
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· Stovall Gathering System. Our Stovall gathering system is located in northern Mississippi and consists of approximately nine miles of natural gas gathering pipeline and a compressor station.
· Enid Pipeline System. Our Enid pipeline system is located in northern Oklahoma and consists of approximately five miles of pipeline.
Compression Assets
We completed construction of our Cedar Hills compression facility and acquired the Horse Creek compression facility in 2002. The Cedar Hills compression facility is comprised of six units with an aggregate of approximately 24,000 horsepower. The Horse Creek compression facility is comprised of two units with an aggregate of approximately 5,300 horsepower.
At the compression facilities, we compress air to pressures in excess of 4,000 pounds per square inch. At our water injection plant, water is produced from source wells located near the water plant site. Produced water is run through a filter system to remove impurities and is then cooled prior to being pumped to pressures in excess of 2,000 pounds per square inch. The air and water are delivered at the tailgate of our facilities into pipelines owned by Continental Resources and are ultimately utilized by Continental Resources in its oil and gas secondary recovery operations. For a description of the services agreement we entered into with Continental Resources in connection with our initial public offering, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Compression Services Agreement.”
Competition
The natural gas gathering, treating, processing and marketing industries are highly competitive. We face strong competition in acquiring new natural gas supplies. Our competitors include other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency, flexibility and reliability of the gatherer, the pricing arrangements offered by the gatherer and the location of the gatherer’s pipeline facilities; a competitive advantage for us because of our proximity to established and new production. We provide flexible services to natural gas producers, including natural gas gathering, compression, dehydrating, treating and processing. We believe our ability to furnish these services gives us an advantage in competing for new supplies of natural gas because we can provide the services that producers, marketers and others require to connect their natural gas quickly and efficiently. In addition, using centralized treating and processing facilities, we can in most cases attract producers that require these services more quickly and at a lower initial capital cost due in part to the elimination of some field equipment. For natural gas that exceeds the maximum carbon dioxide and NGL specifications for interconnecting pipelines and downstream markets, we believe that we offer treating and other processing services on competitive terms. In addition, with respect to natural gas customers attached to our pipeline systems, we provide natural gas supplies on a flexible basis.
We believe that our producers prefer a midstream energy company with the flexibility to accept natural gas not meeting typical industry standard gas quality requirements. The primary difference between us and our competitors is that we provide an integrated and responsive package of midstream services, while most of our competitors typically offer only a few select services. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements that we offer producers, allows us to compete more effectively for new natural gas supplies.
Many of our competitors have capital resources and control supplies of natural gas greater than ours. Our primary competitors on the Eagle Chief gathering system are Western Gas Resources, Inc., Ringwood Gathering, and Duke Energy Field Services. Our primary competitor on the Bakken gathering system and the Badlands gathering system is Bear Paw Energy, and on the Matli gathering system is Enogex Inc. We do not have a major competitor on the Worland gathering system.
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Regulation
Regulation by the FERC of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or the FERC, does not directly regulate any of our operations. However, the FERC’s regulation influences certain aspects of our business and the market for our products. In general, the FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:
· the certification and construction of new facilities;
· the extension or abandonment of services and facilities;
· the maintenance of accounts and records;
· the acquisition and disposition of facilities;
· the initiation and discontinuation of services; and
· various other matters.
In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.
Intrastate Regulation of Natural Gas Transportation Pipelines. We do not own any pipelines that provide intrastate natural gas transportation, so state regulation of pipeline transportation does not directly affect our operations. As with FERC regulation described above, however, state regulation of pipeline transportation may influence certain aspects of our business and the market for our products.
Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC. We own a number of intrastate natural gas pipelines that we believe would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC jurisdiction, were it determined that those intrastate lines should be classified as interstate lines. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts.
In the states in which we operate, regulation of intrastate gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirement and complaint based rate regulation. For example, we are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In certain circumstances, such laws will apply even to gatherers like us that do not provide third party, fee-based gathering service and may require us to provide such third party service at a regulated rate. 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.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent 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. Our gathering operations could be adversely affected should they be subject in the
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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.
Environmental Matters
The operation of pipelines, plants and other facilities for gathering, compressing, dehydrating, treating, or processing of 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, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
· restricting the way we can handle or dispose of our wastes;
· limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
· requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and
· enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, 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 substances or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws
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and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat, fractionate and process natural gas. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of the material environmental and safety laws and regulations that can apply to our operations. We believe that we are in substantial compliance with these environmental laws and regulations.
Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing and treatment plants, fractionation facilities and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies.
Hazardous Waste. Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.
Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum as well as natural gas is excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the Environmental Protection Agency, or EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint
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and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.
Water Discharges. Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material into wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.
Pipeline Safety. Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases, and the transportation and storage of liquefied natural gas (LNG) and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could result in increased costs that, at this time, cannot reasonably be quantified.
The DOT, through the Office of Pipeline Safety, adopted regulations to implement the Pipeline Safety Improvement Act, which requires pipeline operators to, among other things, develop integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. States in which we operate have adopted similar regulations applicable to intrastate gathering and transmission lines. Our pipeline systems are largely excluded from these regulations and are not generally situated within areas that would be designated “high consequence areas”. Therefore, compliance with these regulations has not had a significant impact on our operations.
Employee Health and Safety. We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.
Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans, and exposure can result in death. The gas handled at our Worland gathering system contains high levels of hydrogen sulfide, and we employ numerous safety precautions at the system to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in compliance with all such requirements.
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Title to Properties
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 not been subordinated to the right-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 roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were 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 or will obtain 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 these consents, permits or authorizations will be obtained reasonably soon, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.
We lease the majority of the surface land on which our gathering systems operate. With respect to our Eagle Chief gathering system, we lease the surface land on which the Eagle Chief processing plant, three of the four compressor stations, a produced water dumping station and the three pumping stations are located. With respect to our Bakken gathering system, we own the land on which the processing plant is located and the land on which the compressor stations are located. In our Worland gathering system, we lease the surface land on which the Worland processing plant and the compressor stations are located. With respect to our Badlands gathering system, we own the land on which the Badlands processing plant is located and we lease the land on which the four compressor sites are located. In addition, we lease the surface lands on which our Matli processing plant and compressor station are located.
We believe that we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by our affiliates until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. 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 of our business.
We believe that we either own in fee or have leases, easements, rights-of-way or licenses and have obtained the necessary consents, permits and franchise ordinances to conduct our operations in all material respects.
Office Facilities
In addition to our pipelines and processing facility discussed above, we occupy approximately 7,037 square feet of space at our executive offices in Enid, Oklahoma, under a lease expiring on August 31, 2009. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.
Employees
As of December 31, 2005, our general partner had 67 full-time employees who provide services to us. We are not a party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe we have good relations with our employees. All of our employees are employees of our general partner. In addition, certain of our general partner’s employees provide services
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to Continental Resources in connection with the operation of compression assets owned by Continental Resources.
Address, Internet Website and Availability of Public Filings
We maintain our principal corporate offices at 205 West Maple, Suite 1100, Enid, Oklahoma 73701. Our telephone number is (580) 242-6040. Our Internet address is www.hilandpartners.com. We make the following information available free of charge on our Internet Website:
· Annual Report on Form 10-K;
· Quarterly Reports on Form 10-Q;
· Current Reports on Form 8-K;
· Amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
· Charters for our Audit, Conflicts, and Compensation Committees;
· Code of Business Conduct and Ethics; and
· Code of Ethics for Chief Executive Officer and Senior Financial Officers
We make our SEC filings available on our Website as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. The above information is available in print to anyone who requests it.
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 a similar business. The following risks could materially and adversely affect our business, financial condition or results of operations. In that case, the amount of the distributions on our common units could be materially and adversely affected, the trading price of our common units could decline .
Risks Related to Our Business
We may not have sufficient cash after the establishment of cash reserves and payment of our general partner’s fees and expenses to enable us to pay distributions at the current level.
We may not have sufficient available cash each quarter to pay distributions at the current level. Under the terms of our partnership agreement, we must pay our general partner’s fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. 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:
· the amount of natural gas gathered on our pipelines;
· the throughput volumes at our processing, treating and fractionation plants;
· the price of natural gas;
· the relationship between natural gas and NGL prices;
· the level of our operating costs;
· the weather in our operating areas;
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· the level of competition from other midstream energy companies; and
· the fees we charge and the margins we realize for our services.
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:
· the level of capital expenditures we make;
· the cost of acquisitions, if any;
· our debt service requirements;
· fluctuations in our working capital needs;
· restrictions on distributions contained in our credit facility;
· restrictions on our ability to make working capital borrowings under our credit facility to pay distributions;
· prevailing economic conditions; and
· the amount of cash reserves established by our general partner’s board of directors in its sole discretion for the proper conduct of our business.
A decrease in our cash flow will reduce the amount of cash we have available for distribution to our unitholders.
You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, 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 and may not make cash distributions during periods when we record net income.
A significant decrease in natural gas production in our areas of operation would reduce our ability to make distributions to our unitholders.
Our gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Because we often obtain as new sources of supply associated gas that is produced in connection with oil drilling operations, declines in oil prices, even without a commensurate decline in prices for natural gas, can adversely affect our ability to obtain new gas supplies.
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If we fail to obtain new sources of natural gas supply, our revenues and cash flow may be adversely affected and our ability to make distributions to our unitholders reduced.
We may not be able to obtain additional contracts for natural gas supplies. We face competition in acquiring new natural gas supplies. Competition for natural gas supplies is primarily based on the location of pipeline facilities, pricing arrangements, reputation, efficiency, flexibility and reliability. Our major competitors for natural gas supplies and markets include (1) Western Gas Resources, Inc., Ringwood Gathering and Duke Energy Field Services LLC at our Eagle Chief gathering system, (2) Enogex, Inc. at our Matli gathering system and (3) Bear Paw Energy, a subsidiary of Northern Borders Partners, L.P., at our Badlands and Bakken gathering systems. Many of our competitors have greater financial resources than we do which may better enable them to pursue additional gathering and processing opportunities than us.
We depend on certain key producers for a significant portion of our supply of natural gas, and the loss of any of these key producers could reduce our supply of natural gas and adversely affect our financial results.
For the year ended December 31, 2005, Continental Resources, Chesapeake Energy and Range Resources supplied us with approximately 35.5%, 27.6% and 12.5%, respectively, of our total natural gas volumes. Each of our natural gas gathering systems is dependent on one or more of these producers. To the extent that these producers reduce the volumes of natural gas that they supply us as a result of competition or otherwise, we would be adversely affected unless we were able to acquire comparable supplies of natural gas on comparable terms from other producers, which may not be possible in areas where the producer that reduces its volumes is the primary producer in the area.
We generally do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems; therefore, volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate.
We generally do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have 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 gathered on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our gathering systems would have an adverse effect on our results of operations and financial condition.
We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key 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 customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.
Our cash flow is affected by the volatility of natural gas and NGL product prices, which could adversely affect our ability to make distributions to unitholders.
We are subject to significant risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for the prompt month contract in 2004 ranged from a high of $8.75 per MMBtu to a low of $4.57 per MMBtu. During 2005, the same index ranged from a
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high of $15.38 per MMBtu to a low of $5.79 per MMBtu. A composite of the weighted monthly average NGLs price based on our average NGLs composition in 2004 ranged from a high of approximately $0.96 per gallon to a low of $0.61 per gallon. During 2005, the same composite ranged from approximately $1.15 per gallon to approximately $0.71 per gallon. 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:
· the impact of weather on the demand for oil and natural gas;
· the level of domestic oil and natural gas production;
· the availability of imported oil and natural gas;
· actions taken by foreign oil and gas producing nations;
· the availability of local, intrastate and interstate transportation systems;
· the availability and marketing of competitive fuels;
· the impact of energy conservation efforts; and
· the extent of governmental regulation and taxation.
We operate under two types of contractual arrangements under which our total segment margin is exposed to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and percentage-of-index arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers for an agreed percentage of proceeds or upon an index related price, and then sell the resulting residue gas and NGLs or NGL products at index related prices. Under percentage-of-index arrangements, we purchase natural gas from producers at a fixed percentage of the index price for the natural gas they produce and subsequently sell the residue gas and NGLs or NGL products at market prices. Under both of these types of contracts our revenues and total segment margin increase or decrease, whichever is applicable, as the price of natural gas and NGLs fluctuates. For a detailed discussion of these contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts.”
We may not successfully balance our purchases of natural gas and our sales of residue gas and NGLs, which increases our exposure to commodity price risks.
We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised 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 not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.
Our construction of new assets or the expansion of existing 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 may grow our business is through the construction of new midstream assets or the expansion of existing systems such as our Badlands expansion project. 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 require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule 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 new pipeline, the construction may occur over
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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 oil and natural gas reserves, we often do not have access to 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.
A change in the 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.
As a natural gas gatherer and intrastate pipeline company, we generally are exempt from FERC regulation under the NGA, but FERC regulation still affects our business and the market for our products. FERC’s policies and practices across the range of its 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 natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission service and federally unregulated gathering services is the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts.
Other state and local regulations also affect our business. Our gathering lines are subject to ratable take and common purchaser statutes in states in which we operate. 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 restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. States in which we operate have adopted 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. 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.
We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (i) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (ii)RCRA and comparable state laws that impose requirements for the discharge of waste from our facilities and (iii) CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the
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assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, 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 or other waste products into the environment.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover these costs from insurance.
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
Our ability to grow depends 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, including our recent Bakken acquisition, involves potential risks, including, among other things:
· mistaken assumptions about revenues and costs, including synergies;
· an inability to integrate successfully the businesses we acquire;
· the assumption of unknown liabilities;
· limitations on rights to indemnity from the seller;
· the diversion of management’s attention from other business concerns;
· unforeseen difficulties operating in new product areas or new geographic areas; and
· customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you 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 approach is based, in part, on our expectation of ongoing divestitures of midstream assets by large 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.
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If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy and our cash flows could be adversely affected.
The construction of additions to our existing gathering 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 obtaining new rights-of-way or renewing existing rights-of-way increases, then our cash flows could be adversely affected.
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 the many hazards inherent in the gathering, treating, processing and fractionation of natural gas and NGLs, including:
· damage to pipelines, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;
· inadvertent damage from construction and farm equipment;
· leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of measurement equipment or facilities at receipt or delivery points;
· fires and explosions; and
· other hazards, including those associated with high-sulfur content, or sour gas, 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 incident to our business. In accordance with typical industry practice, 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, other than those considered to be sudden and accidental. In addition, we do not have business interruption insurance. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.
Restrictions in our credit facility limit our ability to make distributions to you and may limit our ability to capitalize on acquisitions and other business opportunities.
Our credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates, make distributions to our unitholders and capitalize on acquisition or other business opportunities. It also contains covenants requiring us to maintain certain financial ratios and tests. We are prohibited from making any distribution to unitholders if such distribution would cause a default or an event of default under our credit facility. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. At December 31, 2005, our total outstanding long-term indebtedness was approximately $33.8 million, all under our senior secured revolving credit facility. Payments of principal and interest on the indebtedness will reduce the cash available for distribution on our units. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness” for a discussion of our credit facility.
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Due to our lack of asset diversification, adverse developments in our midstream operations would reduce our ability to make distributions to our unitholders.
We rely exclusively on the revenues generated from our gathering, dehydration, treating, processing, fractionation and compression services businesses, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to our lack of diversification in asset type, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.
Increases in interest rates, which have recently experienced record lows, could adversely impact our unit price and our ability to issue additional equity to make acquisitions, reduce debt or finance internal growth projects.
If 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. 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 make acquisitions, reduce debt or finance internal growth projects.
Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.
We utilize derivative financial instruments related to the future price of natural gas and to the future price of NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices. While our hedging activities are designed to reduce commodity price risk, we remain exposed to fluctuations in commodity prices to some extent.
The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas prices or NGLs prices that we realize in our operations. Furthermore, our hedges relate to only a portion of the volume of our expected sales and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future sales may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure 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 cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution 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, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging procedures may not be properly followed. We cannot assure you that the steps we take to monitor our derivative financial instruments will detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
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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 the energy transportation 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.
Risks Inherent in an Investment in Us
Harold Hamm controls our general partner, which has sole responsibility for conducting our business and managing our operations. Affiliates of Harold Hamm and our general partner have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.
As of March 9, 2006, the Hamm Parties, including our general partner and its affiliates, owned 54.5% of the units outstanding. In addition, Harold Hamm controls our general partner. Conflicts of interest may arise between Harold Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust, which we collectively refer to as the Hamm Trusts, and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the 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:
· Harold Hamm and the Hamm Trusts own Continental Resources; neither our partnership agreement nor any other agreement requires Continental Resources to pursue a business strategy that favors us;
· our general partner is allowed to take into account the interests of parties other than us, in resolving conflicts of interest;
· 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;
· our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional limited partner securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders;
· 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;
· our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and
· our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.
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Unitholders have limited voting rights and limited ability to influence our operations and activities.
Unitholders have only limited voting rights on matters affecting our operations and activities and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not select our general partner or elect the board of directors of our general partner and effectively have no right to select our general partner or elect its board of directors in the future.
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 the 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 be voted on any matter. In addition, the partnership agreement 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.
Our general partner determines the cost reimbursement and fees payable to it from us; such payments may be substantial and could reduce our cash available for distribution to you.
Payments to our general partner may be substantial and will reduce the amount of available cash for distribution to unitholders. We will reimburse our general partner for the provision by it and its affiliates of various general and administrative services for our benefit, including the salaries and costs of employee benefits for employees of the general partner that provide services to us. Our general partner determines the amount of expenses allocable to us. There is no cap on the amount that may be paid or reimbursed to our general partner for compensation or expenses incurred on our behalf. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner.
Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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. 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;
· provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in our best interests;
· generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
· 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
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misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.
In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.
Harold Hamm and Continental Resources may engage in limited competition with us.
Harold Hamm and Continental Resources and their affiliates may engage in limited competition with us. Pursuant to the omnibus agreement entered into in connection with our initial public offering, Harold Hamm has agreed that neither he nor any of his affiliates (including Continental Resources) will engage in, whether by acquisition, construction, investment in debt or equity interests of any person or otherwise, the business of gathering, treating, processing and transportation of natural gas in North America, the transportation and fractionation of NGLs in North America, and constructing, buying or selling any assets related to the foregoing businesses. This restriction does not apply to:
· any business that is primarily related to the exploration for and production of oil or natural gas, including the sale and marketing of oil and natural gas derived from such exploration and production activities;
· any business conducted by Harold Hamm or his affiliates as of the date of the omnibus agreement;
· the purchase and ownership of not more than five percent of any class of securities of any entity engaged in any restricted business (but without otherwise participating in the activities of such entity);
· any business that Harold Hamm or his affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of less than $5.0 million;
· any business that Harold Hamm or his affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of $5.0 million or more if we have been offered the opportunity to purchase the business for the fair market value or construction cost, as applicable, and we decline to do so with the concurrence of the conflicts committee of our general partner; and
· any business conducted by Harold Hamm or his affiliates with the approval of the conflicts committee.
These non-competition obligations will terminate on the first to occur of the following events:
· the first day on which the Hamm Parties no longer control us;
· the death of Harold Hamm; and
· February 15, 2010, the fifth anniversary of the closing of our initial public offering.
Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.
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 did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they would 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.
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The unitholders are unable initially to remove the general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent 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. As of March 9, 2006, the general partner and its affiliates owned 54.5% of the units outstanding. Also, if the general partner is removed without cause during the subordination period and units held by the 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 the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the 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, gross negligence, 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 the general partner’s performance in managing our partnership would most likely result in the termination of the subordination period.
Furthermore, 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 the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general partner’s 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.
The 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 members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors of our general partner with their own choices and to control the decisions taken by the board of directors.
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.
We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. We can provide no assurance that the general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable to us. Other than option agreements, neither we nor our general partner have entered into any employment agreements with any officers of our general partner. If the general partner fails to provide us with adequate personnel, our operations could be adversely impacted. Certain of our general partner’s employees provide services to Continental Resources in connection with the operation of compression assets owned by Continental Resources. In addition, certain of the officers of our general partner, including the chief executive officer and chief financial officer, may also serve as officers and directors of affiliates of the general partner.
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We may issue additional common units without your approval, which would dilute your existing ownership interests.
During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,360,000 additional common units. Our general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
· the issuance of common units upon the exercise of the underwriters’ over-allotment option;
· the issuance of common units in connection with acquisitions or capital improvements that increase cash flow from operations per unit on an estimated pro forma basis;
· issuances of common units to repay indebtedness, if the cost to service the indebtedness is greater than the distribution obligations associated with the units issued in connection with the repayment of the indebtedness;
· the conversion of subordinated units into common units;
· the conversion of units of equal rank with the common units into common units under some circumstances;
· in the event of a combination or subdivision of common units;
· issuances of common units under our employee benefit plans; or
· the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal or removal of our general partner.
In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.
The issuance 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 may 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 relative voting strength of each previously outstanding unit may be diminished;
· the market price of the common units may decline; and
· the ratio of taxable income to distributions may increase.
After the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.
Our general partner’s discretion in determining the level of cash reserves may reduce the amount of available cash for distribution to you.
Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our
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partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution to you.
Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.
In some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions, or to hasten the expiration of the subordination period.
Our general partner has a limited call right that may require you to sell your 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. As of March 9, 2006, our general partner and its affiliates owned approximately 12.3% of the common units and, at the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 54.5% of the common units.
You could be liable for any and all of our obligations 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. You could be liable for any and all of our obligations as if you were 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
· your 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 to you 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
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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.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity level taxation by individual states. If the Internal Revenue Service, or IRS, treats us as a corporation or we become subject to entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to you.
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 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 income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, our treatment 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, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any of these states were to impose a tax on us, the cash available for distribution to you would be reduced. 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 levels will be adjusted to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
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 prospectus 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 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.
You may be required to pay taxes on income from us even if you 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, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.
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Tax gain or loss on disposition of common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive 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 raise issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts 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 you are a tax-exempt entity or a non-U.S. person, you should consult your 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 take 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 you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election.”
The sale or exchange of 50% or more of our capital and profits interests within a 12-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 12-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. Please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
Unitholders may be subject to state and local taxes and return filing requirements.
In addition to federal income taxes, you 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 you do not live in any of those jurisdictions. You 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 jurisdictions. Further, you may be subject to penalties for failure
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to comply with those requirements. We own assets and do business in North Dakota, Wyoming, Oklahoma, Texas, Mississippi and Montana. Each of these states, other than Texas and Wyoming, currently imposes a personal income tax as well as an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent. However, we cannot assure you 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.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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PART II
Item 5. Market for Registrant’s Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities
Our limited partner common units began trading on the Nasdaq National Market under the symbol “HLND” commencing with our initial public offering on February 10, 2005 at an initial public offering price of $22.50 per common unit. As of March 7, 2006, the market price for the common units was $39.14 per unit and there were approximately 4,500 common unitholders, including beneficial owners of common units held in street name and four record holders of our subordinated units. There is no established public trading market for our subordinated uints. We intend to consider cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our ability to distribute available cash is contractually restricted by the terms of our credit facility. Our credit facility contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distributions to unitholders if the distribution would cause an event of default, or an event of default is existing, under our credit facility. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Indebtedness—Credit Facility.”
The following table shows the high and low closing prices per common unit, as reported by the NASDAQ National Market, for the periods indicated. Cash distributions shown were paid within 45 days after the end of each quarter.
| | Common Unit
Price Ranges | | Cash Distribution | |
Year Ended December 31, 2005 | | | | High | | Low | | Paid Per Unit(a) | |
Quarter Ended December 31 | | $ | 46.47 | | $ | 34.50 | | | $ | 0.6250 | | |
Quarter Ended September 30 | | $ | 46.22 | | $ | 34.58 | | | $ | 0.5125 | | |
Quarter Ended June 30 | | $ | 37.32 | | $ | 31.17 | | | $ | 0.4625 | | |
Quarter Ended March 31 | | $ | 35.00 | | $ | 27.50 | | | $ | 0.2250 | (b) | |
| | | | | | | | | | | | | | |
(a) For each quarter, an identical per unit cash distribution was paid on all outstanding subordinated units.
(b) Reflects the pro rata portion of the $0.45 minimum quarterly distribution per unit, representing the period from the February 15, 2005 closing of our initial public offering through March 31, 2005.
Cash Distribution Policy
Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter: less the amount of cash reserves established by our general partner to provide for the proper conduct of our business; comply with applicable law, any of our debt instruments, or other agreements; or provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under the working capital portion of our credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.
Upon the closing of our initial public offering, affiliates of Harold Hamm, the Hamm Trusts and an affiliate of Randy Moeder received an aggregate of 4,080,000 subordinated units. During the subordination period, the common units will have the right to receive distributions of available cash from operating
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surplus in an amount equal to the minimum quarterly distribution of $0.45 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will extend until the first day of any quarter beginning after March 31, 2010 that each of the following tests are met: distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; the “adjusted operating surplus” (as defined in its partnership agreement) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and there are no arrearages in payment of the minimum quarterly distribution on the common units. If the unitholders remove the general partner without cause, the subordination period may end before March 31, 2010.
In addition, if the tests for ending the subordination period are satisfied for any three consecutive four-quarter periods ending on or after March 31, 2008, 25% of the subordinated units will convert into an equal number of common units. Similarly, if those tests are also satisfied for any three consecutive four-quarter periods ending on or after March 31, 2009, an additional 25% of the subordinated units will convert into an equal number of common units. The second early conversion of subordinated units may not occur, however, until at least one year following the end of the period for the first early conversion of subordinated units.
We will make distributions of available cash from operating surplus for any quarter during any subordination period in the following manner: first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages below.
Our general partner, Hiland Partners GP, LLC, is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
| | Total Quarterly Distribution | | Marginal Percentage
Interest in Distributions | |
| | Target Amount | | Unitholders | | General Partner | |
Minimum Quarterly Distribution | | $0.45 | | | 98 | % | | | 2 | % | |
First Target Distribution | | Up to $0.495 | | | 98 | % | | | 2 | % | |
Second Target Distribution | | Above $0.495 up to $0.5625 | | | 85 | % | | | 15 | % | |
Third Target Distribution | | Above $0.5625 up to $0.675 | | | 75 | % | | | 25 | % | |
Thereafter | | Above $0.675 | | | 50 | % | | | 50 | % | |
The equity compensation plan information required by Item 201(d) of Regulation S-K in response to this item is incorporated by reference into “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters,” of this annual report on Form 10-K.
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Issuer Purchases of Equity Securities
We did not repurchase any of our common units during the fourth quarter of fiscal 2005.
Item 6. Selected Historical Financial and Operating Data
The following table sets forth selected historical financial and operating data of Hiland Partners, LP and our predecessor, Continental Gas, Inc. as of and for the periods indicated. The selected historical financial data as of December 31, 2005 and for the year ended December 31, 2005 are derived from the audited financial statements of Hiland Partners, LP. The selected historical financial data for the years ended December 31, 2004, 2003, 2002 and 2001 are derived from the audited financial statements of Continental Gas, Inc.
The following table includes the non-GAAP financial measures of (1) EBITDA and (2) total segment margin, which consists of midstream segment margin and compression segment margin. We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation, amortization and accretion expense. We define midstream segment margin as midstream revenue less midstream purchases. Midstream purchases include the following costs and expenses: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas and NGLs purchased by us from affiliates, and costs of crude oil purchased by us from third parties. We define compression segment margin as the lease payments received under our compression facilities lease agreement with Continental Resources, Inc. which was restructured as described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items Impacting Comparability of Our Financial Results—Restructuring of Compression Facilities Lease” in connection with our initial public offering. For a reconciliation of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please refer to the reconciliation following the table below.
Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. We treat costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets as operations and maintenance expenses as we incur them.
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The table should be read together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| | Hiland
Partners, LP | | Predecessor
Continental Gas, Inc. | |
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
| | (in thousands, except per unit and operating data) | |
Summary of Operations Data: | | | | | | | | | | | | | |
Total revenues | | | $ | 166,601 | | | $ | 98,296 | | $ | 76,018 | | $ | 35,228 | | $ | 45,489 | |
Operating costs and expenses: | | | | | | | | | | | | | |
Midstream purchases (exclusive of items shown separately below) | | | 133,089 | | | 82,532 | | 67,002 | | 27,935 | | 33,929 | |
Operations and maintenance | | | 7,359 | | | 4,933 | | 3,714 | | 3,509 | | 3,002 | |
Depreciation, amortization and accretion | | | 11,112 | | | 4,127 | | 3,304 | | 2,370 | | 2,072 | |
Property impairment expense | | | — | | | — | | 1,535 | | — | | — | |
(Gain) loss on asset sales | | | — | | | (19 | ) | 34 | | (12 | ) | (76 | ) |
Bad debt expense | | | — | | | — | | — | | 295 | | — | |
General and administrative expenses | | | 2,470 | | | 1,082 | | 770 | | 730 | | 688 | |
Total operating costs and expenses | | | 154,030 | | | 92,655 | | 76,359 | | 34,827 | | 39,615 | |
Operating income (loss) | | | 12,571 | | | 5,641 | | (341 | ) | 401 | | 5,874 | |
Other income (expense): | | | | | | | | | | | | | |
Interest expense | | | (1,942 | ) | | (702 | ) | (473 | ) | (185 | ) | (350 | ) |
Amortization of deferred loan costs | | | (484 | ) | | (102 | ) | (24 | ) | — | | — | |
Interest income and other | | | 192 | | | 40 | | 10 | | 72 | | 95 | |
Total other income (expense) | | | (2,234 | ) | | (764 | ) | (487 | ) | (113 | ) | (255 | ) |
Income (loss) from continuing operations | | | 10,337 | | | 4,877 | | (828 | ) | 288 | | 5,619 | |
Discontinued operations, net | | | — | | | 35 | | 246 | | 199 | | 285 | |
Income (loss) before change in accounting principle | | | 10,337 | | | 4,912 | | (582 | ) | 487 | | 5,904 | |
Cumulative effect of change in accounting principle | | | — | | | — | | 1,554 | | — | | — | |
Net income | | | $ | 10,337 | | | $ | 4,912 | | $ | 972 | | $ | 487 | | $ | 5,904 | |
Net income per limited partner unit, basic(1) | | | $ | 1.33 | | | | | | | | | | |
Net income per limited partner unit, diluted(1) | | | $ | 1.32 | | | | | | | | | | |
Cash distributions per limited partner unit(2) | | | $ | 1.83 | | | | | | | | | | |
Balance Sheet Data (at period end): | | | | | | | | | | | | | |
Property and equipment, at cost, net | | | $ | 120,715 | | | $ | 37,075 | | $ | 38,425 | | $ | 23,722 | | $ | 20,638 | |
Total assets | | | 193,969 | | | 49,175 | | 47,840 | | 28,058 | | 25,435 | |
Accounts payable-affiliates | | | 6,122 | | | 2,998 | | 2,814 | | 2,150 | | 877 | |
Long-term debt, net of current maturities | | | 33,784 | | | 12,643 | | 14,571 | | 3,491 | | 2,975 | |
Net equity | | | 138,589 | | | 24,510 | | 21,739 | | 20,767 | | 20,280 | |
Cash Flow Data: | | | | | | | | | | | | | |
Net cash flow provided by (used in): | | | | | | | | | | | | | |
Operating activities | | | $ | 8,122 | | | $ | 7,957 | | $ | 4,464 | | $ | 4,809 | | $ | 6,432 | |
Investing activities | | | (74,888 | ) | | (5,290 | ) | (17,286 | ) | (5,645 | ) | (3,242 | ) |
Financing activities | | | 72,736 | | | (2,946 | ) | 13,212 | | 516 | | (2,865 | ) |
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Other Financial Data: | | | | | | | | | | | | | |
Midstream segment margin | | | $ | 29,295 | | | $ | 15,764 | | $ | 9,016 | | $ | 7,293 | | $ | 11,560 | |
Compression segment margin | | | 4,217 | | | — | | — | | — | | — | |
Total segment margin | | | $ | 33,512 | | | $ | 15,764 | | $ | 9,016 | | $ | 7,293 | | $ | 11,560 | |
EBITDA | | | $ | 23,875 | | | $ | 9,843 | | $ | 4,773 | (3) | $ | 3,042 | | $ | 8,326 | |
Maintenance capital expenditures | | | $ | 2,225 | | | $ | 1,693 | | $ | 1,769 | | $ | 1,826 | | $ | 844 | |
Expansion capital expenditures | | | 72,723 | | | 3,474 | | 14,900 | | 3,244 | | 2,339 | |
Discontinued operations | | | — | | | 159 | | 745 | | 690 | | 235 | |
Total capital expenditures | | | $ | 74,948 | | | $ | 5,326 | | $ | 17,414 | | $ | 5,760 | | $ | 3,418 | |
Operating Data: | | | | | | | | | | | | | |
Natural gas sales (MMBtu/d) | | | 47,096 | | | 40,560 | | 37,701 | | 26,599 | | 24,117 | |
NGL sales (Bbls/d) | | | 1,965 | | | 1,133 | | 895 | | 950 | | 881 | |
(1) Net income per unit is not applicable for periods prior to our initial public offering.
(2) Includes our cash distribution of $0.625 per unit paid on February 14, 2006.
(3) EBITDA has not been (1) increased for the impact of the $1.5 million non-cash impairment charge for the year ended December 31, 2003 or (2) decreased for the impact of the $1.6 million cumulative effect of accounting change for the year ended December 31, 2003.
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The following table presents a reconciliation of the non-GAAP financial measures of (1) EBITDA to the GAAP financial measure of net income and (2) total segment margin (which consists of the sum of midstream segment margin and compression segment margin) to operating income, in each case, on a historical basis for each of the periods indicated.
| | Hiland
Partners, LP | | Predecessor
Continental Gas, Inc. | |
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
| | (in thousands) | |
Reconciliation of EBITDA to Net Income: | | | | | | | | | | | | | |
Net income | | | $ | 10,337 | | | $ | 4,912 | | $ | 972 | | $ | 487 | | $ | 5,904 | |
Add: | | | | | | | | | | | | | |
Depreciation, amortization and accretion | | | 11,112 | | | 4,127 | | 3,304 | | 2,370 | | 2,072 | |
Amortization of deferred loan costs | | | 484 | | | 102 | | 24 | | — | | — | |
Interest Expense | | | 1,942 | | | 702 | | 473 | | 185 | | 350 | |
EBITDA | | | $ | 23,875 | | | $ | 9,843 | | $ | 4,773 | (1) | $ | 3,042 | | $ | 8,326 | |
Reconciliation of Total Segment Margin to Operating Income (Loss): | | | | | | | | | | | | | |
Operating income (loss) | | | $ | 12,571 | | | $ | 5,641 | | $ | (341 | ) | $ | 401 | | $ | 5,874 | |
Add: | | | | | | | | | | | | | |
Operations and maintenance | | | 7,359 | | | 4,933 | | 3,714 | | 3,509 | | 3,002 | |
Depreciation, amortization and accretion | | | 11,112 | | | 4,127 | | 3,304 | | 2,370 | | 2,072 | |
Property impairment expense | | | — | | | — | | 1,535 | | — | | — | |
(Gain) loss on asset sales | | | — | | | (19 | ) | 34 | | (12 | ) | (76 | ) |
Bad debt expense | | | — | | | — | | — | | 295 | | — | |
General and administrative expenses | | | 2,470 | | | 1,082 | | 770 | | 730 | | 688 | |
Total segment margin | | | $ | 33,512 | | | $ | 15,764 | | $ | 9,016 | | $ | 7,293 | | $ | 11,560 | |
(1) EBITDA has not been (1) increased for the impact of the $1.5 million non-cash impairment charge for the year ended December 31, 2003 or (2) decreased for the $1.6 million cumulative effect of accounting change for the year ended December 31, 2003.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion in conjunction with our Consolidated Financial Statements and notes thereto included elsewhere in this report.
Overview
We are a Delaware limited partnership formed in October 2004 to own and operate the assets that have historically been owned and operated by Continental Gas, Inc. and Hiland Partners, LLC.
Continental Gas, Inc. historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland and Bakken gathering systems. Hiland Partners, LLC historically has owned our Worland gathering system, our compression services assets and the Bakken gathering system. Continental Gas, Inc. is our predecessor for accounting purposes. As a result, our historical financial statements for periods prior to February 15, 2005 are the financial statements of Continental Gas, Inc.
In connection with our initial public offering, the former owners of Continental Gas, Inc. and Hiland Partners, LLC and certain of our affiliates, including our general partner, contributed to us, all of the assets and operations of Continental Gas, Inc., other than a portion of its working capital assets, and
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substantially all of the assets and operations of Hiland Partners, LLC, other than a portion of its working capital assets and the assets related to the Bakken gathering system, in exchange for an aggregate of 720,000 common units and 4,080,000 subordinated units, a 2% general partner interest in us and all of our incentive distribution rights, which entitle the general partner to increasing percentages of the cash we distribute in excess of $0.495 per unit per quarter.
We completed our initial public offering of 2,300,000 common units on February 15, 2005, receiving net proceeds of $48.1 million. The proceeds from the public offering were used to (1) pay remaining offering costs of $2.2 million and deferred debt issuance costs of $0.6 million, (2) pay outstanding indebtedness of $22.9 million, (3) redeem $6.3 million of common units from an affiliate of Harold Hamm and the Hamm Trusts, and (4) make a $3.9 million distribution to the previous owners of Hiland Partners, LLC. We retained $12.2 million to replenish working capital.
Effective September 1, 2005, we consummated the Bakken acquisition pursuant to which we acquired the outstanding membership interests in Hiland Partners, LLC, an Oklahoma limited liability company, for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. Hiland Partners, LLC’s principal asset is the Bakken gathering system located in eastern Montana.
We completed a secondary public offering of 1,630,000 common units on November 21, 2005, receiving net proceeds of $66.1 million including our general partner’s contribution of $1.4 million. We used $65.2 million of the proceeds from the public offeringto repay borrowings under our credit facility which were used for the Bakken acquisition.
We are engaged in gathering, compressing, dehydrating, treating, processing and marketing natural gas, fractionating NGLs and providing air compression and water injection services for oil and gas secondary recovery operations. Our operations are primarily located in the Mid-Continent and Rocky Mountain regions of the United States.
We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into two business segments:
· Midstream Segment, which is engaged in gathering and processing of natural gas primarily in the Mid-Continent and Rocky Mountain regions. Within this segment, we also provide certain related services for compression, dehydrating, and treating of natural gas and the fractionation of NGLs. For the year ended December 31, 2005 this segment generated 87.4% of our total segment margin.
· Compression Segment, which is engaged in providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota. For the year ended December 31, 2005 this segment generated 12.6% of our total segment margin. We had no compression segment prior to February 15, 2005.
Our results of operations are determined primarily by five interrelated variables: (1) the volume of natural gas gathered through our pipelines; (2) the volume of natural gas processed; (3) the volume of NGLs fractionated; (4) the level and relationship of natural gas and NGL prices; and (5) our current contract portfolio. Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon prices and market demand for natural gas and NGLs, which fluctuate with changes in market and economic condition and other factors.
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How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our segment performance. These measurements include the following: (1) natural gas and NGL sales volumes, throughput volumes and fuel consumption by our facilities; (2) total segment margin; (3) operations and maintenance expenses; (4) general and administrative expenses; and (5) EBITDA.
Volumes and Fuel Consumption. Natural gas and NGL sales volumes, throughput volumes and fuel consumption associated with our business are an important part of our operational analysis. We continually monitor volumes on our pipelines to ensure that we have adequate throughput to meet our financial objectives. It is important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes that are connected to those systems. The performance at our processing, fractionation and treating facilities is significantly influenced by the volumes of natural gas that flows through our systems. In addition, we monitor fuel consumption because it has an impact on the total segment margin realized from our midstream operations and our compression services operations.
Total Segment Margin. We view total segment margin as an important performance measure of the core profitability of our operations. We review total segment margin monthly for consistency and trend analysis.
With respect to our midstream segment, we define midstream segment margin as our revenue minus midstream purchases. Revenue includes revenue from the sale of natural gas, NGLs and NGL products resulting from our gathering, treating, processing and fractionation activities and fixed fees associated with the gathering of natural gas and the transportation and disposal of saltwater. Midstream purchases include the cost of natural gas, condensate and NGLs purchased by us from third parties and the cost for the transportation and fractionation of NGLs by third parties. Our midstream segment margin is impacted by our midstream contract portfolio, which is described in more detail below.
With respect to our compression segment, following the restructuring of our lease arrangement to become a service arrangement in connection with our initial public offering as described in “—Items Impacting Comparability of Our Financial Results,” our compression segment margin equals the fee we earn under our Compression Services Agreement with Continental Resources, Inc. for providing air compression and water injection services. The fee that we earn under this agreement is fixed so long as our facilities meet specified availability requirements, regardless of Continental Resources, Inc.’s utilization. As a result, our compression segment margin is dependent on our ability to meet their utilization levels. For a discussion of this agreement, please read “—Our Contracts—Compression Services Agreement.”
Operations and Maintenance Expenses. Operations and maintenance expenses are costs associated with the operation of a specific asset. Direct labor, insurance, ad valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operations and maintenance expenses. These expenses remain relatively stable independent of the volumes through our systems but fluctuate slightly depending on the activities performed during a specific period.
General and Administrative Expenses. Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations.
Our general and administrative expenses have increased as a result of our becoming a public company. These expenses were approximately $2.5 million for 2005 and $1.1 million for 2004. This increase was primarily due to the cost of tax return preparations, accounting support services, filing annual and quarterly reports with the Securities and Exchange Commission, investor relations, directors’ and officers’ insurance and registrar and transfer agent fees.
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In the omnibus agreement that we entered into in connection with our initial public offering, Continental Resources, Inc. agreed to provide the following services to us for two years, at the lower of Continental Resources, Inc.’s cost to provide the services or $50,000 per year:
· information technology support, including supplying our computer servers, repair services and electronic mail; and
· human resource functions, including locating and recruiting potential employees and assistance in complying with certain employment laws and regulations.
EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation, amortization and accretion expense. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:
· the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
· the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
· our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
· the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders and is used as a gauge for compliance with some of our financial covenants under our credit facility. 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.
How We Manage Our Operations
Our management team uses a variety of tools to manage our business. These tools include: (1) flow and transaction monitoring systems; (2) producer activity evaluation and reporting; and (3) imbalance monitoring and control.
Flow and transaction monitoring systems. We utilize a customized system that tracks commercial activity on a daily basis at each of our gathering systems, processing plants and treating and fractionation facilities. We track and monitor inlet volumes to our facilities, fuel consumption, NGLs and NGL products extracted, condensate volumes and residue sales volumes. We also monitor daily operational throughput at our air compression and water injection facilities.
Producer activity evaluation and reporting. We monitor the producer drilling and completion activity in our primary areas of operation to identify anticipated changes in production and potential new well attachment opportunities. The continued connection of natural gas production to our gathering systems is critical to our business and directly impacts our financial performance. Through our relationship with Continental Resources, Inc., we receive weekly summaries of new drilling permits and completion reports filed with the state regulatory agencies that govern these activities on all of our gathering systems other than the Bakken gathering system. Producers that have dedicated acreage to our Bakken gathering system provide us with their projected annual drilling schedules, which are updated periodically. Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel at our corporate offices. These
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processes enhance our awareness of new well activity in our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines.
Imbalance monitoring and control. We continually monitor volumes we deliver to pipelines and volumes nominated for sale on pipelines to ensure we remain within acceptable imbalance limits during a calendar month. We seek to reduce imbalances because of the inherent commodity risk that results when deliveries and sales of natural gas are not balanced concurrently.
Our Contracts
Because of the significant volatility of natural gas and NGL prices, our contract mix can have a significant impact on our profitability. In order to reduce our exposure to commodity price risk, we pursue arrangements under which we purchase natural gas from the producers at the wellhead at an index based price less a fixed fee to gather, dehydrate, compress, treat and/or process their natural gas, referred to as fee based arrangements or contracts, where market conditions permit. Actual contract terms are based upon a variety of factors, including natural gas quality, geographical location, the competitive environment at the time the contract is executed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of producer preferences, our expansion in regions where some types of contracts are more common and other market factors.
Our Natural Gas Sales Contracts
We sell natural gas on intrastate and interstate pipelines to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies and utilities. We typically sell natural gas on a monthly basis under index related pricing terms. In addition, we have forward sales contracts to sell 1) approximately 50,000 MMBtu of natural gas per month through December 2007 with weighted average fixed prices per MMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007, 2) approximately 50,000 MMBtu of natural gas per month from January 2006 through December 2006 with weighted average fixed price per MMBtu of $9.52 and 3) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices per MMBtu of $9.13. The above forward sales contracts relate to volumes from our Eagle Chief and Matli gathering systems.
We also use cash flow hedges to limit our exposure to changing natural gas prices. Under these hedges we settle monthly on the difference between the sales of future production to our counterparty at a fixed price and the price that will be established on the date of hedge settlement by reference to a specified index price. These hedges cover periods of up to ten months from the date of the hedge.
Our NGL Sales Arrangements
We sell NGLs and NGL products at the tailgate of our facilities to ONEOK Hydrocarbon, LP, SemStream, L.P., and a subsidiary of Kinder Morgan Energy Partners, L.P. We typically sell NGLs and NGL products on a monthly basis under index related pricing terms. We also use cash flow hedges to limit our exposure to changing NGL prices. Under these hedges we settle monthly on the difference between the sales of future production to our counterparty at a fixed price and the price that will be established on the date of hedge settlement by reference to a specified index price. These hedges cover periods of up to nineteen months from the date of the hedge.
Hedging Contracts
To insure that our hedging financial instruments will be used solely for hedging price risks and not for speculative purposes, we review our hedges for compliance with our hedging policies and procedures. We recognize gains and losses from the settlement of our hedges in revenue when we sell the associated physical residue natural gas or natural gas liquid. Any gain or loss realized as a result of hedging is
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substantially offset in the market when we sell the physical residue natural gas or natural gas liquid. All of our hedges are characterized as cash flow hedges as defined in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Accounting.” We determine gains or losses on open and closed hedging transactions based upon the difference between the hedge price and the physical price. For a more detailed discussion on our hedging activity, please read commodity price risks included in Item 7A “Quantitative and Qualitative Disclosures about Market Risk”.
Our Natural Gas Purchase Contracts
With respect to our natural gas gathering, compression, dehydrating, treating, processing and marketing activities and our NGL fractionation activities, we contract under the following types of arrangements:
· Percentage-of-proceeds arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, gather, treat, and process the natural gas, in some cases fractionate the NGLs into NGL products, and then sell the resulting residue gas and NGLs or NGL products at index related prices. We remit to the producers either an agreed upon percentage of the proceeds or an index related price for the natural gas and the NGLs. Under these types of arrangements, our revenues and total segment margin correlate directly with the price of natural gas and NGLs. For the year ended December 31, 2005 we purchased 42.8% of our total volumes under these types of fee arrangements.
· Percentage-of-index arrangements. Under percentage-of-index arrangements, we purchase natural gas from the producers at the wellhead at a price that is at a fixed percentage of the index price for the natural gas that they produce. We then gather, treat and process the natural gas, in some cases fractionate the NGLs into NGL products and then sell the residue gas and NGLs or NGL products pursuant to natural gas or NGL arrangements described above. Since under these types of arrangements our costs to purchase the natural gas from the producer is based on the price of natural gas, our total segment margin under these arrangements increases as the price of NGLs increase relative to the price of natural gas, and our total segment margin under these arrangements decreases as the price of natural gas increases relative to the price of NGLs. For the year ended December 31, 2005 we purchased 24.5% of our total volumes under these types of fee arrangements.
· Fixed-fee arrangements. Under fixed-fee arrangements, we purchase natural gas from the producers at the wellhead at an index based price less a fixed fee to gather, dehydrate, compress, treat and/or process their natural gas. These types of arrangements typically require us to pay the producer for the value of the wellhead gas less the applicable fee. For the year ended December 31, 2005 we purchased 32.7% of our total volumes under these types of fee arrangements.
We are a party to a fixed fee gas purchase contract with Continental Resources, Inc. dated as of August 1, 1999. For the year ended December 31, 2005 gas purchased under the contract represented approximately 14.0% of our aggregate natural gas supply. Under the contract, Continental Resources, Inc. has committed to supply us with all of the gas that it produces in a designated area in Blaine County, Oklahoma. The contract currently covers approximately 18 wells that are connected to our Matli gathering system. We pay Continental Resources the applicable index price for the raw natural gas delivered to us, less a transportation fee, a processing fee and a treating fee. The contract remains in effect for the life of the gas leases contained in the dedicated area. However, we have the right to terminate the contract by giving 30 days’ notice.
Compression Services Agreement
Under the compression services agreement that we entered into with Continental Resources, Inc. in connection with our initial public offering and effective as of January 28, 2005, Continental Resources, Inc.
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pays us a fixed monthly fee to provide compressed air and water at pressures sufficient to allow for the injection of either air or water into underground reservoirs for oil and gas secondary recovery operations. Under the compression services agreement, Continental Resources, Inc. is responsible for the provision to us of power and water to be utilized in the compression process. If our facilities do not meet the monthly volume requirements for compressed air and water, and the failure is not attributable to Continental Resources, Inc.’s failure to supply power or water or a force majeure, the fixed monthly payment will be reduced in proportion to the volumes of air or water we were unable to deliver during such month. Continental Resources, Inc. may terminate the compression services agreement if we are unable to deliver any compressed air and water for a period of more than 20 consecutive days and the failure is not attributable to Continental Resources, Inc.’s failure to supply power or water or a force majeure. The agreement has an initial term of four years and will thereafter automatically renew for additional one month terms unless terminated by either party by giving notice at least 15 days prior to the end of the then current term.
Our Growth Strategy
Our growth strategy contemplates engaging in construction and expansion opportunities as well as complementary acquisitions of midstream assets in our operating areas. We intend to pursue construction and expansion projects to meet new or increased demand for our midstream services. In addition, we intend to pursue acquisitions that we believe will allow us to capitalize on our existing infrastructure, personnel and producer and customer relationships to provide an integrated package of services. We may also pursue selected acquisitions in new geographic areas to the extent they present growth opportunities similar to those we are pursuing in our existing areas of operations. To successfully execute our growth strategy, we will require access to capital on competitive terms. We intend to finance future acquisitions primarily by using the capacity available under our bank credit facility and equity or debt offerings or a combination of both.
Capital Expenditures. We make capital expenditures either to maintain our assets or the natural gas supply to our assets or for expansion projects to increase our total segment margin. Maintenance capital is capital employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance. Our decisions whether to spend capital on expansion projects are generally based on the target rate of return, as well as the cash flow capabilities of the assets.
Acquisitions. In analyzing a particular acquisition, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets, strategic fit of the asset in relation to our business strategy, expertise required to manage the asset, capital required to integrate and maintain the asset, and the competitive environment of the area where the assets are located. From a financial perspective, we analyze the rate of return the assets will generate under various case scenarios, comparative market parameters and cash flow capabilities of the assets.
Items Impacting Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either from period to period or going forward, for the reasons described below.
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Our Formation
We were formed in October 2004 to own and operate the assets that have historically been owned and operated by Continental Gas, Inc. and Hiland Partners, LLC. As part of our formation, immediately prior to consummation of our initial public offering, the former owners of Continental Gas, Inc. and Hiland Partners, LLC contributed to us all of the assets and operations of Continental Gas, Inc. other than a portion of its working capital assets and all of the assets and operations of Hiland Partners, LLC, other than a portion of its working capital assets and the assets related to the Bakken gathering system. Effective September 1, 2005, we acquired Hiland Partners, LLC, which owns the Bakken gathering system.
Continental Gas, Inc. is our predecessor for accounting purposes and has historically owned all of our natural gas gathering, processing and fractionation assets other than the Worland and Bakken gathering systems. As a result, our historical financial statements for the periods prior to February 15, 2005 are the financial statements of Continental Gas, Inc.
Hiland Partners, LLC has historically owned our Worland gathering system, our Horse Creek compression facility, our Cedar Hills water injection plant located next to our Cedar Hills compression facility and the Bakken gathering system.
Restructuring of Compression Facilities Lease
Prior to our initial public offering, Hiland Partners, LLC owned our Horse Creek air compression facility and our Cedar Hills water injection facility. In 2002, Hiland Partners, LLC entered into a five year lease agreement with Continental Resources, Inc., pursuant to which Hiland Partners, LLC leased the facilities to Continental Resources, Inc. Continental Resources, Inc. used its own personnel to operate the facilities, and Hiland Partners, LLC made no operational decisions. In connection with our formation and our initial public offering, we entered into a four-year services agreement with Continental Resources, Inc., effective as of January 28, 2005, that replaced the existing lease. Under the services agreement, we own and operate the facilities and provide air compression and water injection services to Continental Resources, Inc. for a fee. As part of the restructuring, the personnel at Continental Resources, Inc. that operated the facilities were transferred to us. Under the new services agreement, we receive a fixed payment of approximately $4.8 million per year as compared to $3.8 million per year under the prior lease agreement. In connection with the new services arrangement, we incur approximately $1.0 million per year in additional operating costs. For a description of the restructured agreement, please read “—Our Contracts—Compression Services Agreement.”
Construction and Acquisition Activities
Since our inception, we have grown through a combination of building gas gathering and processing assets and acquisitions. For example, we commenced operation of the Matli gathering system in 1999 and constructed the Matli processing plant in 2003. Additionally, we acquired the Worland gathering system in 2000 and the Carmen gathering system in 2003. We acquired the Carmen gathering system in 2003 as an expansion of our Eagle Chief gathering system. Prior to our acquisition of the Carmen gathering system, we purchased the gas from the previous owner, processed it and returned it to the previous owner pursuant to a keep-whole arrangement. After we acquired the Carmen gathering system, we terminated this keep-whole arrangement and now sell the gas at the tailgate of the Eagle Chief processing plant. In addition, we completed the Bakken acquisition in September 2005. Our historical 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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Our Results of Operations
Set forth in the table below is financial and operating data for our compression and midstream segments for the periods indicated.
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003(3) | |
| | Hiland
Partners,
LP(1) | | Predecessor(2) | | Total | | Predecessor(2) | |
| | (in thousands) | |
Total Segment Margin Data: | | | | | | | | | | | | | | | |
Midstream revenues | | $ | 150,571 | | | $ | 11,813 | | | $ | 162,384 | | | $ | 98,296 | | | $ | 76,018 | |
Midstream purchases | | 123,342 | | | 9,747 | | | 133,089 | | | 82,532 | | | 67,002 | |
Midstream segment margin | | 27,229 | | | 2,066 | | | 29,295 | | | 15,764 | | | 9,016 | |
Compression revenues(4) | | 4,217 | | | — | | | 4,217 | | | — | | | — | |
Total segment margin(5) | | $ | 31,446 | | | $ | 2,066 | | | $ | 33,512 | | | $ | 15,764 | | | $ | 9,016 | |
Summary of Operations Data: | | | | | | | | | | | | | | | |
Midstream revenues | | $ | 150,571 | | | $ | 11,813 | | | $ | 162,384 | | | $ | 98,296 | | | $ | 76,018 | |
Compression revenues | | 4,217 | | | — | | | 4,217 | | | — | | | — | |
Total revenues | | 154,788 | | | 11,813 | | | 166,601 | | | 98,296 | | | 76,018 | |
Operating costs and expenses: | | | | | | | | | | | | | | | |
Midstream purchases (exclusive of items shown separately below) | | 123,342 | | | 9,747 | | | 133,089 | | | 82,532 | | | 67,002 | |
Operations and maintenance | | 6,579 | | | 780 | | | 7,359 | | | 4,933 | | | 3,714 | |
Property impairment | | — | | | — | | | — | | | — | | | 1,535 | |
Depreciation, amortization and accretion | | 10,600 | | | 512 | | | 11,112 | | | 4,127 | | | 3,304 | |
(Gain) loss on asset sales | | — | | | — | | | — | | | (19 | ) | | 34 | |
General and administrative expenses | | 2,304 | | | 166 | | | 2,470 | | | 1,082 | | | 770 | |
Total operating costs and expenses | | 142,825 | | | 11,205 | | | 154,030 | | | 92,655 | | | 76,359 | |
Operating income (loss) | | 11,963 | | | 608 | | | 12,571 | | | 5,641 | | | (341 | ) |
Other income (expense), net | | (2,119 | ) | | (115 | ) | | (2,234 | ) | | (764 | ) | | (487 | ) |
Income (loss) from continuing operations | | 9,844 | | | 493 | | | 10,337 | | | 4,877 | | | (828 | ) |
Discontinued operations | | — | | | — | | | — | | | 35 | | | 246 | |
Income (loss) before change in accounting principle | | 9,844 | | | 493 | | | 10,337 | | | 4,912 | | | (582 | ) |
Cumulative effect of change in accounting principle | | — | | | — | | | — | | | — | | | 1,554 | |
Net income | | $ | 9,844 | | | $ | 493 | | | $ | 10,337 | | | $ | 4,912 | | | $ | 972 | |
Operating Data (unaudited): | | | | | | | | | | | | | | | |
Natural gas sales (MMBtu/d) | | 48,509 | | | 37,052 | | | 47,096 | | | 40,560 | | | 37,701 | |
NGL sales (Bbls/d) | | 2,071 | | | 1,206 | | | 1,965 | | | 1,133 | | | 895 | |
(1) Amounts presented in the Hiland Partners, LP column include only the activity for the period beginning on the initial public offering date of February 15, 2005. These amounts include the operations of the assets contributed from Hiland Partners, LLC at the closing of our initial public offering (Worland gathering system and compression assets).
(2) Amounts presented in the Predecessor column include only the operations of Continental Gas, Inc. for the period prior to the initial public offering of Hiland Partners, LP on February 15, 2005.
(3) Includes operations of our Carmen gathering system beginning August 1, 2003, the date we acquired these assets.
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(4) Compression revenues and compression segment margin are the same. There are no compression purchases associated with the compression segment.
(5) Reconciliation of total segment margin to operating income:
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003(3) | |
| | Hiland
Partners,
LP(1) | | Predecessor(2) | | Total | | Predecessor(2) | |
| | (in thousands) | |
Operating income (loss) | | $ | 11,963 | | | $ | 608 | | | $ | 12,571 | | | $ | 5,641 | | | $ | (341 | ) |
Add: | | | | | | | | | | | | | | | |
Operations and maintenance expenses | | 6,579 | | | 780 | | | 7,359 | | | 4,933 | | | 3,714 | |
Property impairment | | — | | | — | | | — | | | — | | | 1,535 | |
Depreciation amortization and accretion expenses | | 10,600 | | | 512 | | | 11,112 | | | 4,127 | | | 3,304 | |
(Gain) loss on asset sales | | — | | | — | | | — | | | (19 | ) | | 34 | |
General and administrative expenses | | 2,304 | | | 166 | | | 2,470 | | | 1,082 | | | 770 | |
Total segment margin | | $ | 31,446 | | | $ | 2,066 | | | $ | 33,512 | | | $ | 15,764 | | | $ | 9,016 | |
Year Ended December 31, 2005 Compared with Year Ended December 31, 2004
Revenues. Our total revenues (midstream and compression) were $166.6 million for the year ended December 31, 2005 compared to $98.3 million for the year ended December 31, 2004, an increase of $68.3 million, or 69.5%. This increase was primarily attributable to (1) higher average realized natural gas prices and NGL sales prices, (2) increased volumes attributable to the contribution of the Worland gathering system by Hiland Partners, LLC on February 15, 2005 to us, (3) increased revenues from compression assets contributed by Hiland Partners, LLC on February 15, 2005 to us and (4) increased volumes attributable to the acquisition of the Bakken gathering system effective September 1, 2005.
Our midstream revenues were $162.4 million for the year ended December 31, 2005 compared to $98.3 million for the year ended December 31, 2004, an increase of $64.1 million, or 65.2%. Of this increase, $40.9 million was attributable to higher average realized natural gas prices and NGL sales prices and $23.2 million was attributable to higher residue natural gas and NGL sales volumes. The volume increase is primarily attributable to the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.
Our natural gas sales volumes were 47,096 MMBtu/d for the year ended December 31, 2005 compared to 40,560 MMBtu/d for the year ended December 31, 2004, an increase of 6,536 MMBtu/d, or 16.1%. Our NGL sales volumes were 1,965 Bbls/d for the year ended December 31, 2005 compared to 1,133 Bbls/d for the year ended December 31, 2004, an increase of 832 Bbls/d, or 73.4%. These increases in volumes are primarily associated with the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system from Hiland Partners, LLC effective September 1, 2005.
Our average realized natural gas sales prices were $7.39 per MMBtu for the year ended December 31, 2005 compared to $5.49 per MMBtu for the year ended December 31, 2004, an increase of $1.90 per MMBtu, or 34.6%. In addition, average realized NGL sales prices were $1.01 per gallon for the year ended December 31, 2005 compared to $0.76 per gallon for the year ended December 31, 2004, an increase of $0.25 per gallon or 32.9%. The change in our average realized natural gas and NGL sales prices was
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primarily a result of higher index prices due to a tightening of supply and demand fundamentals for energy, which caused crude oil and natural gas prices to rise during the year ended December 31, 2005 compared to the year ended December 31, 2004.
Our compression revenues were $4.2 million for the year ended December 31, 2005. The compression assets were contributed by Hiland Partners, LLC on February 15, 2005. Continental Gas, Inc., our predecessor, did not have a compression segment, therefore, there were no compression revenues reported for the year ended December 31, 2004.
Midstream Purchases. Our midstream purchases were $133.1 million for the year ended December 31, 2005 compared to $82.5 million for the year ended December 31, 2004, an increase of $50.6 million, or 61.3%. This increase is primarily attributable to increased payments on percent of proceeds and percent of index producer contracts as a result of higher average realized natural gas prices and NGL sales prices, the contribution of the Worland gathering system from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.
Operations and Maintenance. Our operations and maintenance expense totaled $7.4 million for the year ended December 31, 2005 compared with $4.9 million for the year ended December 31, 2004, an increase of $2.4 million, or 49.2%. This increase is primarily attributable to the contribution of the Worland gathering system and the compression assets from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system from Hiland Partners, LLC effective September 1, 2005.
Depreciation, Amortization and Accretion. Our depreciation, amortization and accretion expense totaled $11.1 million for the year ended December 31, 2005 compared with $4.1 million for the year ended December 31, 2004, an increase of $7.0 million, or 169.3%. This increase is primarily attributable to the contribution of the Worland gathering system and the compression assets from Hiland Partners, LLC on February 15, 2005 and the acquisition of the Bakken gathering system effective September 1, 2005.
General and Administrative. Our general and administrative expense totaled $2.5 million for the year ended December 31, 2005 compared with $1.1 million for the year ended December 31, 2004, an increase of $1.4 million, or 128.3%. The increase is primarily attributable to approximately $0.4 million related expenses for adding staff as a result of our growth and approximately $0.7 million additional costs of being a public company.
Other Income (Expense). Our other income (expense) totaled ($2.2) million for the year ended December 31, 2005 compared with ($0.8) million for the year ended December 31, 2004, a increase in expense of $1.5 million, or 192.4%. The increase is primarily attributable to additional interest expense and amortization of deferred debt issuance costs associated with our credit facility relating to the acquisition of the Bakken gathering system effective September 1, 2005.
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Year Ended December 31, 2004 Compared with Year Ended December 31, 2003
Revenues. Midstream revenues were $98.3 million for the year ended December 31, 2004 compared to $76.0 million for the year ended December 31, 2003, an increase of $22.3 million, or 29.3%. Of this increase, $12.7 million was attributable to higher average realized natural gas sales prices and NGL sales prices and $7.2 million was attributable to higher residue and NGL sales volumes.
Natural gas sales volumes were 40,560 MMBtu/d for the year ended December 31, 2004 compared to 37,701 MMBtu/d for the year ended December 31, 2003, an increase of 2,859 MMBtu/d, or 7.6%. NGL sales volumes were 1,133 Bbls/d for the year ended December 31, 2004 compared to 895 Bbls/d for the year ended December 31, 2003, an increase of 238 Bbls/d, or 26.6%. Natural gas and NGL sales volumes increased primarily as a result of our acquisition of the Carmen gathering system from Great Plains Pipeline Company in August 2003.
Average realized natural gas sales prices were $5.49 per MMBtu for the year ended December 31, 2004 compared to $4.84 per MMBtu for the year ended December 31, 2003, an increase of $0.65 per MMBtu, or 13.4%. In addition, average realized NGL sales prices were $0.76 per gallon for the year ended December 31, 2004 compared to $0.58 per gallon for the year ended December 31, 2003, an increase of $0.18 per gallon, or 31.0%. The change in our average realized natural gas and NGL sales prices was primarily a result of higher index prices. The change in index prices was primarily a result of a tightening of supply and demand fundamentals for energy which caused crude oil and natural gas prices to rise significantly during the year ended December 31, 2004 compared to the year ended December 31, 2003.
Midstream Purchases. Midstream purchases were $82.5 million for the year ended December 31, 2004 compared to $67.0 million for the year ended December 31, 2003, an increase of $15.5 million, or 23.2%. This increase was directly attributable to an increase in natural gas and NGL sales volumes as a result of our acquisition of the Carmen gathering system from Great Plains Pipeline Company in August 2003 and an increase in natural gas and NGL prices.
Operations and Maintenance. Operations and maintenance expenses totaled $4.9 million for the year ended December 31, 2004 compared with $3.7 million for the year ended December 31, 2003, an increase of $1.2 million, or 32.8%. The increase was primarily attributable to our acquisition of the Carmen gathering system.
Property Impairment. In 2003, we recognized a $1.5 million impairment expense as a result of volume declines at gathering facilities located in Texas, Mississippi and Wyoming. There was no impairment expense recorded in 2004.
Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expenses totaled $4.1 million for the year ended December 31, 2004 compared with $3.3 million for the year ended December 31, 2003, an increase of $0.8 million, or 24.9%. The increase was primarily due to our acquisition of the Carmen gathering system in August 2003 and expansion of the Matli gathering system in 2003.
General and Administrative. General and administrative expenses totaled $1.1 million for the year ended December 31, 2004 compared with $0.8 million for the year ended December 31, 2003, an increase of $0.3 million, or 40.5%. The increase is associated with an increase in employees caused by our growth and preparation for our initial public offering.
Other Income (Expense). Other income (expense) totaled ($0.8) million for the year ended December 31, 2004 compared with ($0.5) million for the year ended December 31, 2003, an increase of $0.3 million, or 56.9%. This increase relates to the acquisition of the Carmen gathering system in August 2003 and expansion of the Matli Gathering System. We acquired the Carmen gathering system for a net purchase price of $12.0 million that was financed with bank debt.
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Cumulative Effect of Change in Accounting Principle. Cumulative effect of change in accounting principle totaled $1.6 million for the year ended December 31, 2003. In 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method and the liability is accreted to its face amount. We adopted SFAS No. 143 on January 1, 2003. The impact of adopting SFAS No. 143 has been accounted for through a cumulative effect adjustment that amounted to $1.6 million increase to net income recorded on January 1, 2003.
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 expectations may vary materially from actual results. Please see “Forward Looking Statements.”
U.S. Gas Supply and Outlook. We believe that current natural gas prices will continue to result in relatively high levels of natural gas-related drilling as producers seek to increase their level of natural gas production. Although the number of U.S. natural gas wells drilled has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries. We believe that an increase in U.S. drilling activity and additional sources of supply such as liquefied natural gas, or LNG, imports will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States.
A number of the areas in which we operate are experiencing significant drilling activity as result of recent high natural gas prices, new discoveries and the implementation of new exploration and production techniques. We believe that this higher level of activity will continue. We also believe that our Badlands gathering system is located in an area where ongoing secondary recovery operations may provide us with additional natural gas volumes.
While we anticipate continued high levels of exploration and production activities in a number of the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.
Processing Margins. During 2005, 2004 and 2003, we generally have seen our margins increase as natural gas prices and NGL prices have increased, primarily as a result of our percentage-of-proceeds contracts. During 2004 and 2003, this positive impact on our margins had been partially offset by the negative impact on our margins resulting from the price of natural gas increasing relative to the price of NGLs, primarily as a result of our percentage-of-index contracts. Our profitability is dependent upon pricing and market demand for natural gas and NGLs, which are beyond our control and have been volatile.
Rising Interest Rate Environment. If 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. 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,
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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 make acquisitions, reduce debt or for other purposes.
Impact of Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods presented.
Liquidity and Capital Resources
Overview
Cash generated from operations, borrowings under our credit facility and funds from private and future public equity and debt offerings are our primary sources of liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditure requirements. Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.
Cash Flows
Year ended December 31, 2005 Compared to Year ended December 31, 2004
Cash Flows from Operating Activities. Our cash flows from operating activities increased by $0.2 million to $8.1 million for the year ended December 31, 2005 from $7.9 million for the year ended December 31, 2004. We received cash flows from customers of approximately $143.4 million due to increased prices for natural gas and NGLs and higher volumes sold in 2005, had cash payments to our suppliers and employees of approximately $133.9 and payment of interest expense of $1.4 million, net of amounts capitalized, resulting in cash received from our operating activities of approximately $8.1 million. Changes in cash receipts and payments are primarily due to the timing of collections at the end of our reporting periods. We collect and pay large receivables and payables at the end of each calendar month and the timing of these payments and receipts may vary by a day or two between month-end periods, causing these fluctuations. Increased natural gas and natural gas liquids prices together with the acquisition of the Bakken assets contributed to increases in accounts receivable, accrued midstream revenues, accounts payable and accrued midstream purchases during 2005. In connection with our formation, $9.1 million of accounts receivables of Continental Gas, Inc. was retained by the former owners of Continental Gas, Inc. Net income for the year ended December 31, 2005 was $10.3 million, an increase of $5.4 million from a net income of $4.9 million for the year ended December 31, 2004. Our non-cash expenses increased by $7.3 million to $11.6 million in 2005 from $4.3 million in 2004.
Cash Flows Used for Investing Activities. Our cash flows used for investing activities, which represent investments in property and equipment, increased by $69.6 million to $74.9 million for the year ended December 31, 2005 from $5.3 million for the year ended December 31, 2004. Our acquisition of the Bakken gathering system assets totaled approximately $64.6 million.
Cash Flows from Financing Activities. Our cash flows from financing activities increased to $72.7 million for the year ended December 31, 2005 from $(2.9) million for the year ended December 31, 2004. We completed our initial public offering of 2,300,000 common units on February 15, 2005, receiving net proceeds of $48.1 million. The proceeds from the public offering were used to (1) pay remaining offering costs of $2.2 million and deferred debt issuance costs of $0.6 million, (2) pay outstanding indebtedness of $22.9 million, (3) redeem $6.3 million of common units from an affiliate of Harold Hamm
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and the Hamm Trusts, and (4) make a $3.9 million distribution to the previous owners of Hiland Partners, LLC. We retained $12.2 million to replenish working capital. During the period from January 1, 2005 to February 14, 2005, Continental Gas, Inc. repaid $1.1 million of its outstanding indebtedness. On September 26, 2005, we borrowed $93.7 million under our amended credit facility in connection with our acquisition of Hiland Partners, LLC and incurred an additional $0.5 million in debt issuance costs by amending our credit facility. In addition, our cash flows from financing activities for the year ended December 31, 2005 reflect a $27.8 million distribution to the controlling member of our general partner in connection with the acquisition of Hiland Partners, LLC. The controlling member of our general partner owned 49% of Hiland Partners, LLC. The $27.8 million distribution presented in our statement of cash flows reflects the difference in the purchase price paid to the controlling member of our general partner and his cost basis in the net assets of Hiland Partners, LLC. During the third quarter our general partner contributed $7,000 to maintain its 2% interest in us as a result of our issuance of 8,000 restricted common units to non-employee board members of our general partner. On November 21, 2005, we completed our follow-on public offering of 1,630,000 common units, receiving net proceeds, including a $1.4 million contribution from our general partner to maintain its 2% interest in us, less underwriter discount of $3.4 million, of $66.1 million. Offering costs associated with our follow-on public offering totaled $0.6 million. Concurrent with the closing of our secondary public offering, we repaid $65.2 million of our credit facility borrowings we had previously used to fund the Bakken acquisition. During the fourth quarter of 2005, we borrowed $5.3 million under our credit facility to fund capital expansion projects. From February 15, 2005 through December 31, 2005, we distributed $8.3 million to our unitholders.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Cash flows from operating activities. Net cash provided by operating activities was $8.0 million and $4.5 million for 2004 and 2003, respectively, an increase of $3.5 million. Net cash provided by operating activities increased during 2004 principally due to higher total segment margin of $6.7 million. The increase in total segment margin was attributable to an increase in natural gas and NGL prices as well as an increase in natural gas and NGL sales volumes as a result of our acquisition of the Carmen gathering system in August 2003 and expansion of our Matli gathering system throughout 2003. However, this increase was partially offset by higher operating expenses of $1.2 million and changes in working capital items using $1.2 million in 2004 as compared to providing $0.1 million in 2003.
Cash flows used in investing activities. Net cash used in investing activities was $5.3 million for 2004 and $17.3 million for 2003. The year ended December 31, 2003 includes $12.0 million of capital expenditures for our acquisition of the Carmen gathering system. Capital expenditures for additions to property, plant and equipment and acquisitions were $16.7 million in 2003 (net of discontinued operations), which includes $12.0 million of capital expenditures for our acquisition of the Carmen gathering system which is part of our Eagle Chief gathering system and $3.5 million for capital expansion of the Matli gathering system which included construction of the Matli processing plant and a compressor station and $1.2 million for other assets.
Cash flows from financing activities. Net cash provided by (used in) financing activities was ($2.9) million for 2004 and $13.2 million for 2003. For 2004, cash used in financing activities was primarily attributable to our net repayment of $1.9 million in long-term debt. Cash provided by financing activities of $13.2 million for 2003 was attributable to net borrowings of long-term debt primarily for financing the acquisition of the Carmen gathering system.
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Capital Requirements
The midstream energy business is capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:
· maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and
· expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems, processing plants, treating facilities and fractionation facilities and to construct or acquire similar systems or facilities.
Given our objective of growth through acquisitions and expansions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We actively consider a variety of assets for potential acquisitions. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read “—Our Growth Strategy—Acquisitions.”
We believe that cash generated from the operations of our business will be sufficient to meet anticipated maintenance capital expenditures, for which we invested $2.2 million during the year ended December 31, 2005 and have budgeted between $2.7 million and $3.3 million for 2006. We anticipate that expansion capital expenditures will be funded through long-term borrowings or other debt financings and/or equity capital offerings. See “Credit Facility” below for information related to the credit agreement we entered into in February 2005.
Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2005, is as follows:
| | Payment Due by Period | |
| | Total | | Due in | | Due in | | Due in | | | |
Type of Obligation | | | | Obligation | | 2006 | | 2007 | | 2008 | | Thereafter | |
| | (in thousands) | |
Senior secured revolving credit facility(1) | | | $ | 33,784 | | | $ | — | | $ | — | | $ | 33,784 | | | $ | — | | |
Contracts on internal expansion projects(2) | | | 26,820 | | | 23,545 | | 3,275 | | — | | | — | | |
Operating leases | | | 442 | | | 97 | | 109 | | 108 | | | 128 | | |
Total contractual cash obligations | | | $ | 61,046 | | | $ | 23,642 | | $ | 3,384 | | $ | 33,892 | | | $ | 128 | | |
| | | | | | | | | | | | | | | | | | | | | | |
(1) For a discussion of our senior secured revolving credit facility, please read “—Credit Facility” below.
(2) Badlands Expansion Project. On November 8, 2005, we entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources’ secondary oil recovery operations, in the areas specified by the contract. In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the 4th quarter of 2006, is expected to cost approximately $40 million, which we intend to fund using our existing bank credit facility. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system. The cost to expand the system may exceed our expected costs if our assumptions as to construction costs or other factors are incorrect or as a result of other events that are beyond our control.
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(2) Bakken Compressors. We have contractual obligations of $2.1 million to purchase three new compressors which we expect to be operational by the fourth quarter of 2006.
We have entered into certain financial derivative instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate only to forecasted sales in 2006 and 2007. We entered into these instruments to hedge the forecasted natural gas sales against the variability in expected future cash flows attributable to changes in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas is sold. Under these swap agreements, we either receive or pay a monthly net settlement that is determined by the difference between a fixed price and a floating price based on certain indices for the relevant contract period for the agreed upon volumes.
As of December 31, 2005, we had the following natural gas volumes hedged for the periods indicated:
Production Period | | | | Volume | | Average
Fixed Price | | Fair Value
Asset | |
(Calendar year) | | (MMBtu) | | (per MMBtu) | | (in thousands) | |
2006 | | 1,080,000 | | | $ | 8.94 | | | | $ | 868 | | |
2007 | | 1,350,000 | | | $ | 8.03 | | | | 181 | | |
| | | | | | | | | $ | 1,049 | | |
In February 2006, we executed four separate swap contracts relating to portions of our natural gas liquids (NGLs) sales of propane, normal butane, isobutane and normal gasoline from our Matli gathering system for the fixed prices noted below. Under the NGL swap contracts, we will either pay or receive the difference between the fixed prices below and the arithmetic average of the mean of the daily high and low prices for either Mapco propane, normal butane, isobutane or normal gasoline for those issues of Oil Price Information Service (“OPIS”) in the table U.S. & Canada Spot LP-Gas Weekly Averages under the heading Conway/Group 140 Spot Gas Liquids Prices published for the applicable pricing period(s). As a result, we have hedged a portion of our expected exposure to natural gas liquids prices in 2006, 2007 and 2008 at our Matli gathering system. The following table provides information about these financial derivative instruments for the periods indicated:
| | Monthly | | Fixed | |
| | Volume | | Price | |
Natural Gas Liquid Swaps | | | | (BBls) | | ($/Gallon) | |
September 2006 - March 2008 | | | 12,721 | | | | $ | 1.13 | | |
| | | | | | | | | | | | |
In addition to the contractual obligations noted in the table above, as of December 31, 2005, we have fixed price forward sales contracts to sell 1) approximately 50,000 MMBtu of natural gas per month through December 2007 with weighted average fixed prices per MMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007, 2) approximately 50,000 MMBtu of natural gas per month from October 2005 through December 2006 with weighted average fixed prices per MMBtu of $9.52 and 3) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices per MMBtu of $9.13. Such contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.
Off-Balance Sheet Arrangements. We had no other off-balance sheet arrangements as of December 31, 2005.
Credit Facility
Concurrently with the closing of our initial public offering, we entered into a three-year $55.0 million senior secured revolving credit facility. MidFirst Bank, a federally chartered savings association located in
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Oklahoma City, Oklahoma, is a lender and serves as administrative agent under this facility. On September 26, 2005, concurrently with the closing of the Bakken acquisition, we amended this facility to increase our borrowing capacity under the facility to $125.0 million. The facility currently consists of:
· a $117.5 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “revolving acquisition facility”); and
· a $7.5 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “revolving working capital facility”).
In addition, the revolving acquisition facility allows for the issuance of letters of credit of up to $5.0 million in the aggregate. The credit facility will mature in February 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.
Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by us and all of our subsidiaries, other than our operating company, which is the borrower under the credit facility. The credit facility is non-recourse to our general partner.
Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 175 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 275 basis points per annum based on our ratio of total debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus 1/2 of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 30 to 50 basis points per annum based on our ratio of total debt to EBITDA will be payable on the unused portion of the credit facility.
The credit facility prohibits us from making distributions to unitholders if any default or event of default, as defined in the credit facility, has occurred and is continuing or would result from the distribution. In addition, the credit facility contains various covenants that limit, among other things, subject to certain exceptions and negotiated “baskets,” our ability to:
· incur indebtedness;
· grant liens;
· make certain loans, acquisitions and investments;
· make any material changes to the nature of our business;
· amend our material agreements, including the Omnibus Agreement; or
· enter into a merger, consolidation or sale of assets.
The credit facility also contains covenants requiring us to maintain:
· a maximum total debt to EBITDA ratio of 4.5:1.0 for the fiscal quarter ended December 31, 2005; thereafter a maximum total debt to EBITDA ratio of 4.0:1.0;
· a minimum interest coverage ratio of 3.0:1.0; and
· minimum tangible net worth of $15.0 million for the fiscal quarter ended December 31, 2005; thereafter a minimum tangible net worth of $40.0 million.
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Upon the occurrence of an event of default under the credit facility, the lenders may, among other things, be able to accelerate the maturity of the credit facility and exercise other rights and remedies as set forth in the credit facility. Each of the following will be an event of default:
· failure to pay any principal when due or any interest, fees or other amount within 3 business days of when due;
· failure of any representation or warranty to be true and correct in all material respects;
· failure to perform or otherwise comply with the covenants in the credit facility or other loan documents, in certain cases subject to certain grace periods;
· default by us or any of our subsidiaries on the payment of any other indebtedness in excess of $1.0 million, or any default in the performance of any obligation or condition with respect to such indebtedness beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;
· bankruptcy or insolvency events involving us, our general partner or our subsidiaries;
· material default by any party to any material agreement, which is not cured within the time period specified in the material agreement for cure, that is reasonably expected to have a material adverse effect;
· the entry, and failure to pay or contest in good faith, of one or more adverse judgments in an aggregate amount of $500,000 or more in excess of third party insurance coverage;
· a change of control (as defined in the credit facility); and
· invalidity of any loan documentation.
The credit facility limits distributions to our unitholders to Available Cash, and borrowings to fund such distributions are only permitted under the revolving working capital facility. The revolving working capital facility is subject to an annual “clean-down” period of 15 consecutive days in which the amount outstanding under the revolving working capital facility is reduced to zero.
As of December 31, 2005, we had $33.8 million outstanding under the credit facility and were in compliance with our financial covenants.
Recent Accounting Pronouncements
In October 1995, the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004 (collectively, “SFAS 123R”). SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements and that cost will be measured based on the fair value of the equity or liability instruments issued. The effect of the standard will be to require entities to measure the cost of employee services received in exchange for stock or unit options based on the grant-date fair value of the award, and to recognize the cost over the period the employee is required to provide services for the award. We will apply SFAS 123R as of our first interim period beginning on January 1, 2006 and will use the permitted modified prospective method beginning as of the same date. We had 167,500 options outstanding as of December 31, 2005, of which we estimate our unit-based compensation expense to be $312,000, $134,000 and $22,000 for the years ended December 31, 2006, 2007 and 2008, respectively.
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Significant Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve the implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. For further details on our accounting policies, please read Note 1 of the accompanying Notes to Financial Statements.
Asset Retirement Obligations. SFAS No. 143 “Accounting for Asset Retirement Obligations” requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method and the liability is accreted to measure the change in liability due to the passage of time. The primary impact of this standard relates to our estimated costs for dismantling and site restoration of certain of our plants and pipelines. Estimating future asset retirement obligations requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value, generally as estimated by third party consultants. The present value calculation requires us to make numerous assumptions and judgments, including the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required to the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our cash flows.
Impairment of Long-Lived Assets. In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, we evaluate our long-lived assets, including intangible assets, of identifiable business activities for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the volume of reserves providing asset cash flow and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including, but not limited to:
· changes in general economic conditions in regions in which our products are located;
· the availability and prices of NGL products and competing commodities;
· the availability and prices of raw natural gas supply;
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· our ability to negotiate favorable marketing agreements;
· the risks that third party oil and gas exploration and production activities will not occur or be successful;
· our dependence on certain significant customers and producers of natural gas; and
· competition from other midstream service providers, processors, including major energy companies.
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
In December 2003, as a result of volume declines at gathering facilities located in Texas, Mississippi and Wyoming, Continental Gas, Inc. recognized an impairment charge of $1.5 million. No impairment charges were recognized during each of the years ended December 31, 2005 and 2004.
Revenue Recognition. Revenues for sales of natural gas and NGLs product sales are recognized at the time the product is delivered and title is transferred. Revenues from compressor leasing operations were recognized when earned ratably as due under the lease. Revenues from oil and gas production (discontinued operations) were recorded in the month produced and title was transferred to the purchaser. Under the compression services agreement that we entered into with Continental Resources, Inc. in connection with our initial public offering, revenues are recognized when the services under the agreement are performed. For a description of this service agreement, please read “—Our Contracts—Compression Services Agreement.”
Derivatives. We utilize derivative financial instruments to reduce commodity price risks. We do not hold or issue derivative financial instruments for trading purposes. Statement of Financial Accounting Standards (or SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, which was amended in June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149, establishes accounting and reporting standards for derivative instruments and hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial condition and measure those instruments at fair value. Derivatives that are not designated as hedges are adjusted to fair value through income. If the derivative is designated as a hedge, depending upon the nature of the hedge, changes in the fair value of the derivatives are either offset against the fair value of assets, liabilities or firm commitments through income, or recognized in other comprehensive income until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value is immediately recognized into income. If a derivative no longer qualifies for hedge accounting the amounts in accumulated other comprehensive income will be immediately charged to operations.
Disclosure Regarding Forward-Looking Statements
This annual report on Form 10-K includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements include statements regarding our plans, goals, beliefs or current expectations. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although we believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.
Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. Such factors include:
· the general economic conditions in the United States of America as well as the general economic conditions and currencies in foreign countries;
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· the continued ability to find and contract for new sources of natural gas supply;
· the amount of natural gas transported on our gathering systems;
· the level of throughput in our natural gas processing and treating facilities;
· the fees we charge and the margins realized for our services;
· the prices and market demand for, and the relationship between, natural gas and NGLs;
· energy prices generally;
· the level of domestic oil and natural gas production;
· the availability of imported oil and natural gas;
· actions taken by foreign oil and gas producing nations;
· the political and economic stability of petroleum producing nations;
· the weather in our operating areas;
· the extent of governmental regulation and taxation;
· hazards or operating risks incidental to the transporting, treating and processing of natural gas and NGLs that may not be fully covered by insurance;
· competition from other midstream companies;
· loss of key personnel;
· the availability and cost of capital and our ability to access certain capital sources;
· changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations;
· the costs and effects of legal and administrative proceedings;
· the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to the our financial results; and
· risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Our future results will depend upon various other risks and uncertainties, including, but not limited to those described under “Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors Related to our Business.” Other unknown or unpredictable factors also could have material adverse effects on our future results. You should not put undue reliance on any forward-looking statements. All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement. We undertake no duty to update our forward-looking statements.
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk for natural gas and NGLs. We also incur, to a lesser extent, risks related to interest rate fluctuations. We do not engage in commodity energy trading activities.
Commodity Price Risks. Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and demand for NGLs and natural gas, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors—Risk Factors Related to our Business—Our cash flow is affected by the volatility of natural gas and NGL product prices, which could adversely affect our ability to make distributions to unitholders.” To illustrate the impact of changes in prices for natural gas and NGLs on our operating results, we have provided the table below, which reflects, for the year ended December 31, 2005, the impact on our total segment margin of a $0.01 per gallon change (increase or decrease) in NGL prices coupled with a $0.10 per MMBtu change (increase or decrease) in the price of natural gas. The magnitude of the impact on total segment margin of changes in natural gas and NGL prices presented may not be representative of the magnitude of the impact on total segment margin for different commodity prices or contract portfolios. Natural gas prices can also affect our profitability indirectly by influencing the level of drilling activity and related opportunities for our services.
| | | | Natural Gas Price
Change ($/MMBtu) | |
| | | | $0.10 | | $(0.10) | |
NGL Price | | $0.01 | | $ | 356,000 | | $ | 83,000 | |
Change ($/gal) | | $(0.01) | | $ | 67,000 | | $ | (195,000 | ) |
We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets and the use of derivative contracts. In the fourth quarter of 2005 we executed swap contracts relating to a portion of our residue gas sales from our Bakken gathering system that settle against natural gas market prices. In February 2006, we executed swap contracts relating to a portion of our natural gas liquid sales from our Matli system that settle against various NGL market prices. As a result of these derivative contracts, we have hedged a portion of our expected exposure to natural gas prices in 2006 and 2007 at our Bakken gathering system and a portion of our expected exposure to natural gas liquids prices in 2006, 2007 and 2008 at our Matli gathering system. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.
The following table provides information about our derivative instruments for the periods indicated:
| | | | Average | |
| | Volume | | Fixed Price | |
Natural Gas Swaps | | | | (MMBtu) | | (per MMBtu) | |
2006 | | 1,080,000 | | | $ | 8.94 | | |
2007 | | 1,350,000 | | | $ | 8.03 | | |
| | | | | | | | | | |
| | | | Average | |
| | Volume | | Fixed Price | |
NGL Swaps | | | | (Bbls) | | (per gallon) | |
2006 | | 50,884 | | | $ | 1.13 | | |
2007 | | 152,652 | | | $ | 1.13 | | |
2008 | | 38,163 | | | $ | 1.13 | | |
| | | | | | | | | | |
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In addition to the derivative instruments noted in the table above, we have executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month through December 2007 with weighted average fixed prices per MMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007. We also have fixed price physical forward sales contracts to sell 1) approximately 50,000 MMBtu of natural gas per month from January 2006 through December 2006 with weighted average fixed prices per MMBtu of $9.52 and 2) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices per MMBtu of $9.13. Such contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.
Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which has floating interest rates. As of December 31, 2005, we had approximately $33.8 million of indebtedness outstanding under our credit facility. The impact of a 100 basis point increase or decrease in interest rates on this amount of debt would result in an increase or decrease in interest expense, and a corresponding decrease or increase in net income of approximately $0.3 million annually.
Credit Risk. Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. Tenaska Marketing Ventures, OGE Energy Resources, Inc. and BP Energy Company were our largest customers for the year ended December 31, 2005, accounting for approximately 23.4%, 15.9% and 13.4%, respectively, of our revenues. Consequently, changes within one or more of these companies’ operations have the potential to impact, both positively and negatively, our credit exposure. Our counterparty for our derivative instruments as of Devember 31, 2005 is BP Energy Company.
Item 8. Financial Statements and Supplementary Data
The See our Financial Statements beginning on page F-1 for the information required by this Item.
Item 9. Changes in and Disagreements on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
(a) Evaluation of disclosure controls and procedures.
Our principal executive officer and principal financial officer have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by the annual report on Form 10-K. Based on that evaluation, the principal executive officer and principal financial officer concluded that the design and operation of our disclosure controls and procedures are effective in ensuring that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
(b) Changes in internal control over financial reporting.
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There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Item 9B. Other Information
There have been no events that occurred in the fourth quarter of 2005 that would need to be reported on Form 8-K that have not been previously reported.
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PART III
Item 10. Directors and Executive Officers of the Registrant
As is the case with many publicly traded partnerships, we do not have officers, directors or employees. Our operations and activities are managed by our general partner, Hiland Partners GP, LLC. References to our officers, directors and employees are references to the officers, directors and employees of Hiland Partners GP, LLC. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders, as limited by our partnership agreement.
The following table shows information regarding the current directors and executive officers of Hiland Partners GP, LLC. Directors are elected for one-year terms.
Name | | | | Age | | Position with Hiland Partners GP, LLC |
| | | | |
Harold Hamm | | 60 | | Chairman of the Board of Directors |
Randy Moeder | | 45 | | Chief Executive Officer, President and Director |
Ken Maples | | 43 | | Chief Financial Officer, Vice President—Finance, Secretary and Director |
Clint Duty | | 46 | | Vice President—Southern Region Operations and Engineering |
Ron Hill | | 55 | | Vice President—Business Development |
Robert Shain | | 55 | | Vice President—Northern Region Operations and Engineering |
Michael L. Greenwood | | 50 | | Director |
Edward D. Doherty | | 70 | | Director |
Rayford T. Reid | | 57 | | Director |
Shelby E. Odell | | 66 | | Director |
Harold Hamm was elected Chairman of the Board of Directors of our general partner in October 2004 and serves as a member of the compensation committee of the board of directors of our general partner. Mr. Hamm has served as President and Chief Executive Officer and as a director of Continental Gas, Inc. since December 1994 and then served as Chief Executive Officer and a director to 2004. Since its inception in 1967 until October 2005, Mr. Hamm served as President and Chief Executive Officer and a director of Continental Resources, Inc. and currently serves as its Chief Executive Officer and Chairman of its board of directors. Mr. Hamm is also President of the National Stripper Well Association, President and Chairman of the executive board of the Oklahoma Independent Petroleum Association and a member of the executive board of the Oklahoma Energy Explorers. In addition, Mr. Hamm is the founder and serves as Chairman of the board of directors of Save Domestic Oil, Inc. and is a director of Complete Production Services, Inc.
Randy Moeder was elected Chief Executive Officer, President and a director of our general partner in October 2004. Mr. Moeder has been Manager of Hiland Partners, LLC since its inception in October 2000. He also has been President of Continental Gas, Inc. since January 1995 and was Vice President from November 1990 to January 1995. Mr. Moeder was Senior Vice President and General Counsel of Continental Resources, Inc. from May 1998 to August 2000 and was Vice President and General Counsel from November 1990 to April 1998. From January 1988 to summer 1990, Mr. Moeder worked in private law practice. From 1982 to 1988, Mr. Moeder held various positions with Amoco Corporation. Mr. Moeder is a member of the Oklahoma Independent Petroleum Association and the Oklahoma and American Bar Associations. Mr. Moeder holds a Bachelor of Science degree in accounting from Kansas State University and a doctorate of jurisprudence from the University of Tulsa. Mr. Moeder is also a Certified Public Accountant.
Ken Maples was elected Chief Financial Officer, Vice President—Finance, Secretary and a director of our general partner in October 2004. Mr. Maples has served as Chief Financial Officer of Continental
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Gas, Inc. and Hiland Partners, LLC since February 2004. Mr. Maples was Director of Business Development and Manager of Investor Relations of Continental Resources, Inc. from October 2002 to February 2004. From October 1990 to October 2002, Mr. Maples held various positions with Callon Petroleum Company. He holds a Bachelor degree in accounting from Mississippi State University and an MBA from Louisiana State University.
Clint Duty was elected as Vice President—Operations and Engineering of our general partner in November 2004. Effective March 20, 2006 with the hiring of Robert Shain as Vice President Northern Region Operations and Engineering, Mr. Duty assumed the position of Vice President Southern Region Operations and Engineering. Although new to Continental Gas, Inc. and Hiland Partners, LLC, Mr. Duty has extensive experience in operations and engineering management of natural gas gathering, treating, processing and fractionation facilities. From November 2003 until October 2004, Mr. Duty served as Director of Engineering and Construction for Red Cedar Gathering Company in Durango, Colorado. Mr. Duty was recalled to active duty military service (Navy) from December 2002 until October 2003 in support of Operation Iraqi Freedom. Prior to that, from January 2000 until December 2002, Mr. Duty held several managerial positions at CMS Field Services in Tulsa, Oklahoma. From February 1996 until December 1999, Mr. Duty worked for Koch Hydrocarbon Company as Engineering Manager at its Medford, Oklahoma and Mont Belvieu, Texas liquid hydrocarbon complexes. He holds a Bachelor of Science degree in Chemical Engineering from the University of Washington.
Ron Hill was elected as Vice President of Business Development in January 2006. Mr. Hill has spent 29 years in the oil and natural gas industry with a 25-year focus in gas processing, midstream gas gathering, transportation and NGL marketing. From October 2001 until January 2006, Mr. Hill served as Vice President Gas Supply for Pioneer Gas Pipeline, Inc. in San Angelo, Texas. From November 1991 until October 2001, Mr. Hill was Senior Representative Business Development for Western Gas Resources, Inc. in Oklahoma City, Oklahoma and Midland, Texas. Prior to November 1991, Mr. Hill served in a variety of commercial roles for Union Texas Petroleum Corporation, Tipperary Corporation and Texaco, Inc.
Robert Shain was elected as our VicePresident Northern Region Operations & Engineering in March 2006. Mr. Shain has over 30 years in the oil and gas industry. The majority of his experience has been in the engineering and operations of midstream natural gas gathering, compression, processing and treating, along with business development and marketing. From July 2003 until March 2006, Mr. Shain served as Vice President of Operations and Engineering for Seminole Gas Company, LLC (successor to Impact Energy, LTD) in Tulsa, Oklahoma. From May 1995 until July 2003 Mr. Shain served in a variety of commercial roles, most recently of which was Vice President of Commercial Services, for CMS Field Serivces, LLC (successor to Heritage Gas Services, LLC) also in Tulsa, Oklahoma, in which he was responsible for the development and management of operating and capital budgets.
Michael L. Greenwood was elected as a director of our general partner in February 2005, and serves as Chairman of the audit committee and conflicts committee and as a member of the compensation committee of the board of directors of our general partner. Mr. Greenwood is founder and managing director of Carnegie Capital LLC, a financial advisory services firm providing investment banking assistance to the energy industry. Mr. Greenwood previously served as Vice President—Finance and Treasurer of Energy Transfer Partners, L.P. until August 2004. Prior to its merger with Energy Transfer, Mr. Greenwood served as Vice President and Chief Financial Officer & Treasurer of Heritage Propane Partners, L.P. from 2002 to 2003. Prior to joining Heritage Propane, Mr. Greenwood was Senior Vice President, Chief Financial Officer and Treasurer for Alliance Resource Partners, L.P. from 1994 to 2002. Mr. Greenwood has over 20 years of diverse financial and management experience in the energy industry during his career with several major public energy companies including MAPCO Inc., Penn Central Corporation, and The Williams Companies. Mr. Greenwood also serves as a director of Libra Natural Resources plc and Global Power Equipment Group Inc. Mr. Greenwood holds a Bachelor of Science in
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Business Administration degree from Oklahoma State University and a Master of Business Administration degree from the University of Tulsa.
Edward D. Doherty was elected as a director of our general partner in February 2005, and serves as Chairman of the compensation committee and as a member of the audit and conflicts committees of the board of directors of our general partner. Mr. Doherty served as the Chairman and Chief Executive Officer of Kaneb Pipe Line Company LLC, the general partner of Kaneb Pipe Line Partners L.P. since its inception in September 1989 until July 2005. Prior to joining Kaneb, Mr. Doherty was President and Chief Executive Officer of two private companies which provided restructuring services to troubled companies and was President and Chief Executive Officer of Commonwealth Oil Refining Company, Inc., a public refining and petrochemical company. Mr. Doherty holds a Bachelor of Arts degree from Lafayette College and a Doctor of Jurisprudence from Columbia University School of Law.
Rayford T. Reid was elected as a director of our general partner in May 2005, and serves as a member of the compensation committee of the board of directors of our general partner. Mr. Reid has more than 30 years of investment banking, financial advisory and commercial banking experience, including 25 years focused on the oil and gas industry. During the last 20 years, Mr. Reid has served as President of R. Reid Investments Inc., a private investment banking firm which exclusively serves companies engaged in the energy industry. Reid Investments specializes in mergers, acquisitions and divestitures and traditional and non-traditional private placements of debt and equity. Mr. Reid holds a Bachelor of Arts degree from Oklahoma State University and a Master of Business Administration degree from the Wharton School of the University of Pennsylvania.
Shelby E. Odell was elected as a director of our general partner in September 2005 and serves as a member of our audit and conflicts committees of the board of directors of our general partner. Mr. Odell has 40 years experience in the petroleum business, including marketing, distribution, acquisitions, innovation of new asset opportunities, and management. From 1974 to 2000, Mr. Odell held several positions with Koch Industries. He retired in 2000 as President of Koch Hydrocarbon Company and Sr. Vice President of Koch Industries. Prior to joining Koch, Mr. Odell advanced through several positions with Phillips Petroleum Company. He is a past member of the Board of Directors of the Gas Processors Association and holds an Associate Degree in Accounting from Enid Business College.
Board Committees
The board of directors of our general partner has established three committees: conflicts committee, audit committee and compensation committee. The conflict committee reviews specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates and must meet the independence and experience standards established by the NASDAQ National Market and the SEC to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders. The chairman of the conflicts committee is Michael L. Greenwood and Edward D. Doherty and Shelby E. Odell serve as members of the conflicts committee.
In addition, we have an audit committee of three independent directors that review our external financial reporting, recommend engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. The chairman of the audit committee is Michael L. Greenwood and Edward D. Doherty and Shelby E. Odell serve as members on the audit committee.
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We also have a compensation committee of four directors who oversee compensation decisions for the officers of our general partner as well as the compensation plans described below. The chairman of the compensation committee is Edward D. Doherty and Michael L. Greenwood, Harold Hamm and Rayford T. Reid serve as members of the compensation committee.
Our committee charters and governance guidelines, as well as our Code of Business Conduct and Ethics that applies to all officers, directors and employees and our Code of Ethics for the Chief Executive and Senior Financial Officers are available on our website at www.hilandpartners.com. In addition, printed versions of the foregoing are available to any unitholder upon request by writing to Ken Maples, Hiland Partners, LP, 205 West Maple, Suite 1100, Enid, Oklahoma, 73701. We intend to disclose any amendment to or waiver of our Code of Business Conduct and Ethics and Code of Ethics for the Chief Executive and Senior Financial Officers on behalf of an executive officer or director either on our website or in a Form 8-K filing pursuant to Item 5.05 thereof.
Audit Committee
Hiland Partners GP, LLC’s audit committee is composed of three directors who are not officers or employees of Hiland Partners, LP or any affiliates of the general partner and satisfy the independence and experience standards established by the NASDAQ National Market and the SEC to serve on an audit committee of a board of directors.
The board of directors of Hiland Partners GP, LLC has adopted a written charter for the audit committee. The board of directors of Hiland Partners GP, LLC has determined that a member of the audit committee, namely Mr. Greenwood, is an audit committee financial expert (as defined by the SEC) and has designated Mr. Greenwood as the audit committee financial expert. Mr. Greenwood is the Chairman of the Audit committee.
The audit committee is responsible for the selection of Hiland Partners, LP’s independent auditor and reviews the professional services they provide. It reviews the scope of the audit performed by the independent auditor, the audit report issued by the independent auditor, Hiland Partners, LP’s annual and quarterly financial statements, any material comments contained in the auditor’s letters to management, Hiland Partners, LP’s internal accounting control and such other matters relating to accounting, auditing and financial reporting as it deems appropriate. In addition, the audit committee reviews the type and extent of any non-audit work being performed by the independent auditor and its compatibility with their continued objectivity and independence.
Report of the Audit Committee for the Year Ended December 31, 2005
Our management is responsible for our internal controls and our financial reporting process. Grant Thornton LLP, our independent registered public accounting firm for the year ended December 31, 2005, is responsible for performing an independent audit of our consolidated financial statements in accordance with standards of the Public Company Accounting Oversight Board and to issue a report thereon. Our audit committee monitors and oversees these processes. Our audit committee, made up of members of our general partner’s Board of Directors, is responsible for the selection of our independent registered public accounting firm.
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Our audit committee has reviewed and discussed our audited consolidated financial statements with our management and the independent registered public accounting firm. Our audit committee has discussed with Grant Thornton LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended, “Communications with Audit Committees,” including that firm’s independence.
Members of the Audit Committee:
Michael L. Greenwood
Edward D. Doherty
Shelby E. Odell
Section 16(a) Beneficial Ownership Reporting Compliance
Based on our records, except as hereinafter set forth, we believe that during 2005 all of such reporting persons complied with the Section 16(a) filing requirements applicable to them. A Form 4 for Michael L. Greenwood, which was due on February 17, 2005, was filed late on March 16, 2005.
Item 11. Executive and Director Compensation
Reimbursement of Expenses of Our General Partner
Our general partner will not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates will be reimbursed for all expenses incurred on our behalf. These expenses include the cost of employee, officer and director compensation benefits properly allocable to our partnership and all other expenses necessary or appropriate to the conduct of our business and allocable to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its discretion. There is no cap on the amount that may be paid or reimbursed to our general partner for compensation or expenses incurred on our behalf. Continental Resources currently provides us with certain general and administration services. For a description of these services, please read “Certain Relationships and Related Party Transactions—Agreements with Harold Hamm and His Affiliates—Omnibus Agreement—Services.” In the omnibus agreement, Continental Resources has agreed to continue to provide these services to us for two years after our initial public offering, at the lower of Continental Resources’ cost to provide the services or $50,000 per year.
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Executive Compensation
We and our general partner were formed in October 2004, but conducted no business until February 15, 2005. As such, the compensation set forth below includes salary and bonus information paid to each of the named executive officers by us and, prior to February 15, 2005, our predecessor. We have not accrued any obligations with respect to management incentive or retirement benefits for our general partners’ directors and officers for the 2005 fiscal year. We have not entered into any agreement with our general partner relating to the amount of compensation of our executive officers, individually or as a group. The officers and employees of our general partner and our partnership, our subsidiaries or our affiliates may participate in employee benefit plans and arrangements sponsored by our general partner or our partnership, including plans and arrangements that may be established in the future. We reimburse our general partner for expenses incurred on our behalf, including the costs of our executive officer compensation. The following table sets forth certain compensation information of our executive officers. Other than the option agreements described below, neither we nor our general partner have entered into any employment agreements with any officers of our general partner.
| | Summary Compensation Table | |
| | | | | | | | Long-Term | |
| | | | | | | | Compensation | |
| | | | | | | | Units | |
| | Annual Compensation | | Underlying | |
Name and Principal Position | | | | Year | | Salary | | Bonus | | Options | |
Randy Moeder | | 2005 | | $ | 186,923 | | $ | 7,984 | | | 32,000 | | |
President and Chief | | | | | | | | | | | |
Executive Officer | | | | | | | | | | | |
Ken Maples | | 2005 | | $ | 148,031 | | $ | 5,724 | | | 20,000 | | |
Vice President—Finance, Secretary | | | | | | | | | | | |
and Chief Financial Officer | | | | | | | | | | | |
Clint Duty | | 2005 | | $ | 129,000 | | $ | — | | | 20,000 | | |
Vice President Southern Region | | | | | | | | | | | |
Operations and Engineering | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Option Grants, Exercises and Year-End Options Values
Upon completion of our initial public offering, we granted 72,000 common unit options to our executive officers. The options have an exercise price equal to $22.50 per share, which was the initial public offering price, and otherwise have the terms described below under Long-Term Incentive Plan. On February 15, 2006, one third of the aforementioned common unit options vested and subsequently were exercised in February 2006. The following table provides information regarding individual grants of unit options made during fiscal year 2005 to each of the named executive officers
| | Option Grants in Last Fiscal Year | | Potential Realized Value | |
| | Number of | | % of Total | | | | | | at Assumed Annual Rates | |
| | Securities | | Options Granted | | | | | | of Unit Price Appreciation | |
| | Underlying | | to Employees | | Exercise | | Expiration | | for Option Term(1) | |
Name | | | | Options Granted | | in Fiscal Year | | Price ($/unit) | | Date | | 5% ($) | | 10% ($) | |
Randy Moeder | | | 32,000 | | | | 19.1 | % | | | $ | 22.50 | | | February 9, 2015 | | $ | 453,000 | | $ | 1,147,000 | |
Ken Maples | | | 20,000 | | | | 11.9 | % | | | $ | 22.50 | | | February 9, 2015 | | $ | 283,000 | | $ | 717,000 | |
Clint Duty | | | 20,000 | | | | 11.9 | % | | | $ | 22.50 | | | February 9, 2015 | | $ | 283,000 | | $ | 717,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
(1) These amounts represent the result of calculations at the 5% and 10% assumed compounded appreciation rates from the date of grant to the end of the option term (i.e., the expiration date) as required by the SEC by Item 402(c)(2)(vi)(A) of Regulation S-K and are not intended to forecast the future trading prices of our common units.
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The following table provides information about the number of units issued upon option exercises by the named executive officers during 2005, and the value realized by the named executive officers. The table also provides information about the number and value of options that were held by the named executive officers at December 31, 2005.
Aggregated Option Exercise in Last Fiscal Year
and Fiscal Year End Option Values
| | | | | | Number of Securities | | | | |
| | | | | | Underlying | | Value of Unexercised | | |
| | Units | | | | Unexercised Options | | In-the-Money Options | | |
| | Acquired | | Realized | | at December 31, 2005 | | at December 31, 2005(1) | | |
Name | | | | on Exercise | | Value | | Exercisable | | Unexercisable | | Exercisable | | Unexercisable | | |
Randy Moeder | | | — | | | | $ | — | | | | — | | | | 32,000 | | | | $ | — | | | | $ | 458,000 | | |
Ken Maples | | | — | | | | $ | — | | | | — | | | | 20,000 | | | | $ | — | | | | $ | 286,000 | | |
Clint Duty | | | — | | | | $ | — | | | | — | | | | 20,000 | | | | $ | — | | | | $ | 286,000 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) Value is based on the $36.81 closing price of our common units on December 31, 2005.
Compensation of Directors
Officers or employees of our general partner or its affiliates who also serve as directors do not receive additional compensation. Directors who are not officers or employees of our general partner receive (a) a $25,000 annual cash retainer fee, (b) $1,500 for each regularly scheduled meeting attended, (c) $750 for each special meeting attended and (d) 2,000 restricted units upon becoming a director and 1,000 restricted units on each anniversary date of becoming a director. In addition to the foregoing, each director who serves on a committee receives $1,000 for each committee meeting attended, the chairman of our audit committee receives an annual retainer of $5,000 and the chairmen of our other committees receives an annual retainer of $2,500. In addition, each non-employee director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law. The restricted units vest in quarterly increments on the anniversary of the grant date over a period of four years. The weighted average fair value at grant date of the 8,000 restricted units issued in 2005 was $39.69 per unit. Periodic distributions on the restricted units are held in trust by our general partner until the units vest. As a result of the restricted common units issued, our general partner contributed $7,000 to us to maintain its 2% ownership. During 2005, we recorded $317,000 as unearned compensation in owners’ equity based on the fair market value of the units on the date of grant. Unit-based compensation expense related to the restricted units was $28,000 for the year ended December 31, 2005.
Long-Term Incentive Plan
Our general partner has adopted the Hiland Partners Long-Term Incentive Plan for employees and directors of our general partner and employees of its affiliates. The plan is intended to promote our interests and the interests of our general partner by providing to employees and directors of our general partner and its affiliates incentive compensation awards for superior performance that are based on units. The plan is also contemplated to enhance the ability of our general partner, its affiliates or us to attract and retain the services of individuals who are essential for our growth and profitability and to encourage them to devote their best efforts to advancing our business. The long-term incentive plan currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units and phantom units granted under the plan. No more than 225,000 of the 680,000 common units may be issued
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with respect to vested restricted or phantom units. The plan is administered by the compensation committee of our general partner’s board of directors. The plan will continue in effect until the earliest of (i) the date determined by the board of directors of our general partner; (ii) the date that common units are no longer available for payment of awards under the plan; or (iii) the tenth anniversary of the plan.
Our general partner’s board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or its compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are listed at that time. No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant.
Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. The compensation committee may make grants of restricted units and phantom units under the plan to employees and directors containing such terms as the compensation committee shall determine under the plan, including the period over which restricted units and phantom units granted will vest. The committee may, in its discretion, base its determination on the grantee’s period of service or upon the achievement of specified financial objectives. In addition, the restricted and phantom units will vest upon a change of control of us or our general partner, subject to additional or contrary provisions in the award agreement.
If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise or unless otherwise provided in a written employment agreement between the grantee and our general partner or its affiliates. Common units to be delivered with respect to these awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.
Distributions on restricted units may be subject to the same vesting requirements as the restricted units, in the compensation committee’s discretion. The compensation committee, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. These are rights that entitle the grantee to receive cash equal to the cash distributions made on the common units.
We intend for the restricted units and phantom units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for the units.
Unit Options. The long-term incentive plan permits the grant of options covering common units. The compensation committee may make grants under the plan to employees and directors containing such terms as the committee shall determine. Except in the case of substitute options granted to new employees or directors in connection with a merger, consolidation or acquisition, unit options may not have an exercise price that is less than the fair market value of the units on the date of grant. In addition, unit options granted will generally become exercisable over a period determined by the compensation committee and, in the compensation committee’s discretion, may provide for accelerated vesting upon the achievement of specified performance objectives. The unit options will become exercisable upon a change
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in control of us or of our operating company. Unless otherwise provided in an award agreement, unit options may be exercised only by the participant during his lifetime or by the person to whom the participant’s right will pass by will or the laws of descent and distribution. If a grantee’s employment or membership on the board of directors terminates for any reason, the grantee’s unvested options will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise or unless otherwise provided in a written employment agreement or the option agreement between the grantee and our general partner or its affiliates. If the exercise of an option is to be settled in common units rather than cash, the general partner will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner or any combination of the foregoing. The general partner will be entitled to reimbursement by us for the difference between the cost incurred by it in acquiring these common units and the proceeds it receives from a grantee at the time of exercise. Thus, the cost of the unit options above the proceeds from grantees will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will pay us the proceeds it received from the grantee upon exercise of the unit option. The plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders.
Unit Option Grant Agreement. As of January 1, 2006, we have granted options to purchase an aggregate of 167,500 common units with a weighted average exercise price of $24.70 to employees, officers and directors of our general partner. Please see the option grant table above for a description of grants made to named executive officers during 2005. Under the unit option grant agreements, the options vest and may be exercised in one third increments on the anniversary of the grant date over a period of three years. In addition, the unit options will vest and become exercisable, subject to certain conditions, upon the occurrence of any of the following
· the grantee becomes disabled;
· the grantee dies;
· the grantee’s employment is terminated other than for cause; and
· upon a change of control of the Partnership. .
In February 2006, one third of the 143,000 options granted on February 15, 2005 vested. Of the 47,666 options that vested, 39,633 were exercised in February 2006, resulting in cash contributions to us of $0.9 million.
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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 6, 2006 held by:
· each person who beneficially owned 5% or more of the then outstanding units;
· each member of the board of directors and our general partner;
· each named executive officer of our general partner; and
· all directors and officers of our general partner as a group.
Name of Beneficial Owner | | | | Common Units
Beneficially
Owned | | Percentage of
Common Units
Beneficially
Owned | | Subordinated
Units
Beneficially
Owned | | Percentage of
Subordinated
Units
Beneficially
Owned | | Percentage of
Total Units
Beneficially
Owned | | |
Harold Hamm(1)(2) | | | 245,872 | | | | 5.6 | % | | | 2,400,602 | | | | 58.8 | % | | | 31.2 | % | | |
Harold Hamm DST Trust(2)(3) | | | 131,442 | | | | 3.0 | % | | | 990,440 | | | | 24.3 | % | | | 13.2 | % | | |
Harold Hamm HJ Trust(2)(4) | | | 87,627 | | | | 2.0 | % | | | 660,293 | | | | 16.2 | % | | | 8.8 | % | | |
Randy Moeder(1) | | | 54,816 | | | | 1.2 | % | | | 28,665 | | | | | * | | | 1.0 | % | | |
Ken Maples(1) | | | 20,000 | | | | | * | | | — | | | | — | | | | | * | | |
Clint Duty(1) | | | — | | | | — | | | | — | | | | — | | | | — | | | |
Ron Hill(1) | | | — | | | | — | | | | — | | | | — | | | | — | | | |
Robert Shain(1) | | | — | | | | — | | | | — | | | | — | | | | — | | | |
Michael L. Greenwood(1) | | | 10,291 | (5) | | | | * | | | — | | | | — | | | | | * | | |
Edward D. Doherty(1) | | | 2,000 | (5) | | | | * | | | — | | | | — | | | | | * | | |
Rayford T. Reid(1) | | | 14,818 | (5) | | | | * | | | — | | | | — | | | | | * | | |
Shelby E. Odell(1) | | | 2,000 | (5) | | | | * | | | — | | | | — | | | | | * | | |
All directors and executive officers as a group (8 persons) | | | 349,797 | | | | 8.0 | % | | | 2,429,267 | | | | 59.5 | % | | | 32.8 | % | | |
* Less than 1%.
(1) The address of this person is 205 West Maple, Suite 1100, Enid, Oklahoma 73701.
(2) Harold Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust have a 90.7%, 5.6% and 3.7% ownership interest, respectively, in Continental Gas Holdings, Inc., which, as of October 1, 2005, beneficially owned 271,082 common units and 2,646,749 subordinated units. The units held by Continental Gas Holdings, Inc. are reported in this table as beneficially owned by Mr. Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust in proportion to their respective ownership interest in Continental Gas Holdings, Inc. The address of Continental Gas Holdings, Inc. is 205 West Maple, Suite 1100, Enid, Oklahoma 73701.
(3) Mr. Bert Mackie is the trustee of the Harold Hamm DST Trust, and his address is c/o Security National Bank, 201 West Broadway, Enid, Oklahoma 73702-1272.
(4) Mr. Bert Mackie is the trustee of the Harold Hamm HJ Trust, and his address is c/o Security National Bank, 201 West Broadway, Enid, Oklahoma 73702-1272.
(5) 2,000 of the indicated common units are restricted units that vest in quarterly increments on the anniversary of the grant date over a period of four years.
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The following table shows the beneficial ownership of our general partner as of March , 2006 held by the Hamm Parties, the directors of our general partner, each named executive officer and by all directors and officers of our general partner as a group.
Name of Beneficial Owner | | | | Class A
Membership Interest | | Class B
Membership Interest | |
Harold Hamm(1)(2) | | | 94.0 | % | | | 55.7 | % | |
Harold Hamm DST Trust(2) | | | — | | | | 23.0 | % | |
Harold Hamm HJ Trust(2) | | | — | | | | 15.3 | % | |
Randy Moeder | | | 4.0 | % | | | 4.0 | %(3) | |
Ken Maples | | | 2.0 | % | | | 2.0 | %(4) | |
Clint Duty | | | — | | | | — | | |
Ron Hill | | | — | | | | — | | |
Robert Shain | | | — | | | | — | | |
Michael L. Greenwood | | | — | | | | — | | |
Edward D. Doherty | | | — | | | | — | | |
Rayford T. Reid | | | — | | | | — | | |
Shelby E. Odell | | | — | | | | — | | |
All directors and executive officers as a group (8 persons) | | | 100.0 | % | | | 61.7 | % | |
(1) Harold Hamm is the sole member of HH GP Holding LLC, which owns a 94.0% Class A membership interest in our general partner. The interests held by HH GP Holding LLC are reported in this table as beneficially owned by Mr. Hamm.
(2) Continental Gas Holdings, Inc. owns a 61.0% Class B membership interest in our general partner. The interest held by Continental Gas Holdings, Inc. is reported in this table as beneficially owned by Mr. Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust in proportion to their respective ownership of Continental Gas Holdings, Inc.
(3) Includes a 3.3% unvested Class B membership interest that vests in equal increments annually over a three year period commencing on February 15, 2005. One-third of the Class B membership interest vested on February 15, 2006.
(4) Represents an unvested Class B membership interest that vests in equal increments annually over a three year period commencing on February 15, 2005. One-third of the Class B membership interest vested on February 15, 2006.
Under the terms of our general partner’s limited liability company agreement, its membership interests are divided into two classes—Class A Units and Class B Units. Except as described below, only holders of Class A Units are entitled to vote on matters submitted to the members for approval, including the election of our general partner’s directors. Class B Units are not entitled to vote on any matters other than any consolidation, merger, liquidation, dissolution or winding-up of our general partner or any sale by our general partner of all or substantially all of its assets. Distributions by our general partner to its members shall be made only to holders of Class B Units in respect of their Class B Units on a pro rata basis. Holders of Class A Units will generally not be entitled to receive any distributions from our general partner in respect of their Class A Units.
Generally, no member may transfer their interests in our general partner without the approval of the holders of a majority of the Class A Units. Harold Hamm and certain of his affiliates and any other holder of Class A Units or Class B Units who, together with its affiliates holds at least a majority of the outstanding Class A Units, has the right to transfer units to another person without the approval of the board of directors or any member of our general partner. In addition, if one or more holders of Class B Units proposes to transfer Class B Units representing 50% or more of the outstanding Class B Units, then
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such selling holders have the right to require all other holders of Class B Units to sell their Class B Units to the proposed transferee on the same terms.
A portion of Mr. Moeder’s andMr. Maples’ Class B Units are unvested and will vest in equal increments annually over a three-year period commencing on February 15, 2005. In addition, any unvested units will become fully vested upon the disability, death or termination other than for cause of such individual or a change of control of our general partner. If Messrs. Moeder or Maples cease to be an officer or employee of our general partner for any reason, then our general partner has the right to purchase all of such individual’s vested Class B Units for fair market value and all of such individual’s Class A Units and unvested Class B Units for nominal consideration. In addition, if Messrs. Moeder or Maples becomes disabled, dies or is terminated without cause, such individual will be entitled to sell his units to our general partner at those same prices.
Item 13. Certain Relationships and Related Transactions
The general partner and its affiliates own 539,757 common units and 4,080,000 subordinated units representing a 54.5% limited partner interest in us. In addition, the general partner will continue to own a 2% general partner interest in us and the incentive distribution rights.
Distributions and Payments to Our General Partner and its Affiliates
Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses, salaries and benefits for all of our employees and other corporate overhead. Our general partner determines the amount of these expenses. In the omnibus agreement, Continental Resources has agreed to continue to provide certain general and administrative services to us for two years after our initial public offering, at the lower of Continental Resources’ cost to provide the services and $50,000 per year. Please read “—Omnibus Agreement—Services” below. In addition, our general partner owns the 2% general partner interest and all of the incentive distribution rights. 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.
Omnibus Agreement
Upon the closing of our initial public offering, we entered into an omnibus agreement with Continental Resources, Hiland Partners, LLC, Harold Hamm, Continental Gas Holdings, Inc. and our general partner that addressed the following matters:
· for a two-year period, Continental Resources will provide certain general and administrative services;
· Harold Hamm’s agreement not to compete and to cause his affiliates (including Continental Resources) not to compete with us under certain circumstances;
· an indemnity by Continental Resources, Hiland Partners, LLC and Continental Gas Holdings, Inc. for prior tax liabilities resulting from the assets contributed to the partnership;
· an indemnity by Continental Resources for liabilities associated with oil and gas properties conveyed by Continental Gas to Continental Resources by dividend; and
· our two-year exclusive option to purchase the Bakken gathering system owned by Hiland Partners, LLC.
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Services
Continental Resources has agreed to provide us the following services:
· information technology support, including supplying our computer servers, repair services and electronic mail; and
· human resource functions, including locating and recruiting potential employees and assistance in complying with certain employment laws and regulations.
Continental Resources is obligated to provide these services to us for two years after our initial public offering, at the lower of Continental Resources’ cost to provide the services or $50,000 per year.
Non-Competition
Harold Hamm will not, and will cause his affiliates not to engage in, whether by acquisition, construction, investment in debt or equity interests of any person or otherwise, the business of gathering, treating, processing and transportation of natural gas in North America, the transportation and fractionation of NGLs in North America, and constructing, buying or selling any assets related to the foregoing businesses. This restriction does not apply to:
· any business that is primarily related to the exploration for and production of oil or natural gas, including the sale and marketing of oil and natural gas derived from such exploration and production activities;
· the purchase and ownership of not more than five percent of any class of securities of any entity engaged in the business described above;
· any business conducted by Harold Hamm or his affiliates as of the date of the omnibus agreement;
· any business that Harold Hamm or his affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of less than $5.0 million;
· any business that Harold Hamm or his affiliates acquires or constructs that has a fair market value or construction cost, as applicable, of $5.0 million or more if we have been offered the opportunity to purchase the business for the fair market value or construction cost, as applicable, and we decline to do so with the concurrence of the conflicts committee of our general partner; and
· any business conducted by Harold Hamm or his affiliates, with the approval of the conflicts committee.
These non-competition obligations will terminate on the first to occur of the following events:
· the first day on which the Hamm Parties no longer control us;
· the death of Harold Hamm; and
· February 15, 2010, the fifth anniversary of the closing of our initial public offering.
Indemnification
Continental Resources, Hiland Partners, LLC and Continental Gas Holdings, Inc. agreed to indemnify us for all federal, state and local income tax liabilities attributable to the operation of the assets contributed by such entities to us prior to the closing of our initial public offering. In addition, Continental Resources agreed to indemnify us for a period of five years from the closing date of our initial public offering for liabilities associated with oil and gas properties conveyed by Continental Gas to Continental Resources by dividend.
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Option to Purchase the Bakken Gathering System
The omnibus agreement also contains the terms under which we held an option to purchase the Bakken gathering system from Hiland Partners, LLC. Pursuant to the acquisition agreement described below, the omnibus agreement was amended to provide for the purchase of the membership interests in Hiland Partners, LLC instead of the Bakken gathering system, and in September 2005 we purchased all of the outstanding membership interests in Hiland Partners, LLC.
Acquisition Agreement
On September 9, 2005, we, through our operating company, entered into an acquisition agreement with Hiland Partners, LLC and its members pursuant to which we acquired the outstanding membership interests in Hiland Partners, LLC for approximately $92.7 million in cash, consisting of a cash payment of approximately $57.7 million to the former members of Hiland Partners, LLC and the repayment of approximately $35.0 million of bank indebtedness of Hiland Partners, LLC. The acquisition closed on September 26, 2005 and had an effective date of September 1, 2005. The membership interests in Hiland Partners, LLC acquired by us were owned 49% by Harold Hamm, 49% by the Hamm Trusts, and 2% by Equity Financial Services, Inc., whose sole shareholder, director and executive officer is Randy Moeder. Accordingly, Mr. Hamm, the Hamm Trusts and Equity Financial Services, Inc. received approximately $28.3 million, $28.3 million and $1.2 million, respectively, in connection with the transaction, subject to certain closing adjustments. A mutually-agreed-upon investment banking firm determined the fair market value of the Bakken gathering system, the principal asset of Hiland Partners, LLC, and the conflicts committee of the board of directors of our general partner, consisting of its independent directors, approved the transaction.
Contracts with Continental Resources, Inc.
Compression Services Agreement
Prior to our initial public offering, Hiland Partners, LLC leased certain compression assets (which were contributed to us in connection with our initial public offering) to Continental Resources. Hiland Partners, LLC received $3.9 million and $3.3 million for the years ended December 31, 2004 and 2003, respectively under this arrangement. In connection with our initial public offering, we entered into a four-year compression services agreement with Continental Resources as described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Contracts—Compression Services Agreement.” For the year ended December 31, 2005, we received revenues of $4.2 million from Continental Resources under this arrangement.
Gas Purchase Contracts
We purchase natural gas and NGLs from Continental Resources and its affiliates. We purchased natural gas and NGLs from Continental Resources and its affiliates in the amount of approximately $45.8 million, $27.6 million and $26.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Badlands Purchase Contract
On November 8, 2005, we entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources’ secondary oil recovery operations, in the areas specified by the contract. In return, we will receive 50% of the proceeds attributable to residue gas and natural gas liquids sales as well as certain fixed fees associated with gathering and treating the natural gas,
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including a $0.60 per Mcf fee for the first 36 Bcf of natural gas gathered. The board of directors, as well as the conflicts committee of the board of directors, of our general partner have approved the agreement.
In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the 4th quarter of 2006, is expected to cost approximately $40 million, which we intend to fund using our existing bank credit facility. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system.
Other Agreements
Historically, our predecessor and Hiland Partners, LLC have contracted for down hole well services, fluid supply and oil field services from businesses in which Harold Hamm and members of his family have historically owned equity interests. Mr. Hamm and members of his family sold these businesses to Complete Production Services, Inc. in October 2004. Mr. Hamm is currently a director and stockholder of Complete Production Services. Payments made for these services by our predecessor and Hiland Partners, LLC on a combined basis were $219,000, $257,000 and $225,000 during the years ended December 31, 2005, 2004 and 2003, respectively. We continued to obtain services from these companies following completion of our initial public offering. Based on various bids received by our general partner from unaffiliated third parties, our general partner believes that amounts paid for these services are comparable to those amounts which would be charged by an unaffiliated third party.
In addition, in prior periods Hiland Partners, LLC compensated Equity Financial Services, Inc., an entity wholly owned by our President, Randy Moeder, for management and administrative services. Total payments to Equity Financial Services were approximately $11,000, $65,000 and $65,000 during the years ended December 31, 2005, 2004 and 2003, respectively. Following completion of our initial public offering, this service arrangement was terminated.
We lease office space under operating leases from an entity which is wholly owned by Harold Hamm. Rents paid under these leases totaled approximately $75,000, $51,000 and $47,000 for the years ended December 31, 2005, 2004 and 2003, respectively. These rates are consistent with the rates charged to other non-affiliated tenants in the offices.
In connection with the completion of our initial public offering, we adopted an ethics policy that requires related party transactions be reviewed to ensure that they are fair and reasonable to us. This requirement is also contained in our partnership agreement.
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Item 14. Principle Accountant Fees and Services
Our audit committee has also adopted an audit committee charter, which is available on our website at www.hilandpartners.com. The charter requires our audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. Our audit committee ratified Grant Thornton LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of Hiland Partners, LP for the year ended December 31, 2005. Fees paid to Grant Thornton LLP for audit services included fees associated with the annual audit, regulatory filings required in our initial and secondary public offerings, preparation for Sarbanes-Oxley Section 404 attest services and reviews of our quarterly reports on Form 10-Q. Additional fees paid to Grant Thornton LLP for audit-related services consisted of consultation regarding an acquisition and for tax consisted of compliance and advisory services. Fees paid to Grant Thornton LLP are as follows:
| | 2005 | | 2004 | |
Audit Fees | | $ | 328,000 | | $ | 539,000 | |
Audit Related Fees | | 1,000 | | — | |
Tax Fees | | 158,000 | | — | |
All Other Fees | | — | | — | |
Total | | $ | 487,000 | | $ | 539,000 | |
The amount paid to Grant Thornton, LLP for 2004 represents fees for professional services provided in connection with the audit of Continental Gas, Inc., Hiland Partners, LLC and Hiland Partners, LP annual financial statements, review of quarterly financial statements, and audits performed as part of registration filings.
85
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) Financial Statements
The financial statements listed in the accompanying Index to Consolidated Financial Statements are filed as part of this Annual Report on Form 10-K.
(b) Other Information
None.
EXHIBITS
Exhibit
Number | | | | Description | |
| 2.1 | | | — | | Acquisition Agreement by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of September 1, 2005 (incorporated by referenced to Exhibit 2.1 of Registrant’s Form 8-K filed September 29, 2005) | |
| 3.1 | | | — | | Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by referenced to Exhibit 3.1 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| 3.2 | | | — | | First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to exhibit 3.2 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 3.3 | | | — | | Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| 3.4 | | | — | | Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to exhibit 3.4 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 10.1 | | | — | | Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and MidFirst Bank (incorporated by reference to exhibit 10.1 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 10.2 | * | | — | | Hiland Partners, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| 10.3 | | | — | | Compression Services Agreement, effective as of January 28, 2005, by and among Hiland Partners, LP and Continental Resources, Inc. (incorporated by reference to exhibit 10.3 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| †10.4 | | | — | | Gas Purchase Contract between Continental Resources, Inc. and Continental Gas, Inc. (incorporated by reference to Exhibit 10.4 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| †10.5 | | | — | | Gas Purchase Contract Chesapeake Energy Marketing, Inc. and Continental Gas, Inc. (incorporated by reference to Exhibit 10.5 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| †10.6 | | | — | | Gas Purchase Contract between Magic Circle Energy Corporation and Magic Circle Gas (incorporated by reference to Exhibit 10.6 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| †10.7 | | | — | | Gas Purchase Contract between Range Resources Corporation and Continental Gas, Inc. (incorporated by reference to Exhibit 10.7 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
86
| 10.8 | | | — | | Contribution, Conveyance and Assumption Agreement among Hiland Partners, LP, Hiland Operating, LLC, Hiland GP, LLC, Hiland LP, LLC, Continental Gas, Inc., Hiland Partners GP, LLC, Hiland Partners, LLC, Continental Gas Holdings, Inc., Hiland Energy Partners, LLC, Harold Hamm, Harold Hamm HJ Trust, Harold Hamm DST Trust, Equity Financial Services, Inc., Randy Moeder, and Ken Maples effective as of February 15, 2005 (incorporated by reference to exhibit 10.8 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 10.9 | * | | — | | Form of Unit Option Grant (incorporated by reference to Exhibit 10.9 of Registrant’s Registration Statement on Form S-1 (File No. 333-119908)) | |
| 10.10 | | | — | | Omnibus Agreement among Continental Resources, Inc., Hiland Partners, LLC, Harold Hamm, Hiland Partners GP, LLC, Continental Gas Holdings, Inc., and Hiland Partners, LP effective as of February 15, 2005 (incorporated by reference to exhibit 10.10 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 10.11 | * | | — | | Director’s Compensation Summary (incorporated by reference to exhibit 10.11 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 10.12 | * | | — | | Form of Restricted Unit Grant Agreement (incorporated by reference to exhibit 10.1 of Registrant’s Form 8-K filed on November 14, 2005) | |
| 10.13 | | | — | | First Amendment, dated as of September 26, 2005 to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to exhibit 10.1 of Registrant’s Form 8-K filed on September 29, 2005) | |
| 10.14 | | | — | | Gas Purchase Agreement among Hiland Partners, LP and Continental Resources, Inc. dated November 8, 2005 (incorporated by reference to exhibit 10.1 of Registrants form 8-K filed on November 10, 2005) | |
| 19.1 | | | — | | Code of Ethics for Chief Executive Officer and Senior Finance Officers (incorporated by reference to exhibit 19.1 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 21.1 | | | — | | List of Subsidiaries of Hiland Partners, LP (incorporated by reference to exhibit 21.1 of Registrant’s annual report on Form 10-K filed on March 30, 2005) | |
| 31.1 | | | — | | Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002 | |
| 31.2 | | | — | | Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002 | |
| 32.1 | | | — | | Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002 | |
| 32.2 | | | — | | Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002 | |
† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
* Constitutes management contracts or compensatory plans or arrangements.
87
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 to be signed on its behalf by the undersigned, thereunto duly authorized in the city of Enid, Oklahoma, on the 30th day of March, 2006.
| Hiland Partners, LP |
| By: Hiland Partners GP, LLC, its general partner |
| By: | | /s/ RANDY MOEDER |
| | | Randy Moeder |
| | | Chief Executive Officer, President and Director |
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 in the capacities indicated on the 30th day of March, 2006.
| Signature | | | | Title | |
/s/ HAROLD HAMM | | Chairman of the Board |
Harold Hamm | | |
/s/ RANDY MOEDER | | Chief Executive Officer, President and Director |
Randy Moeder | | |
/s/ KEN MAPLES | | Chief Financial Officer, Vice President—Finance, |
Ken Maples | | Secretary and Director |
/s/ MICHAEL L. GREENWOOD | | Director |
Michael L. Greenwood | | |
/s/ EDWARD D. DOHERTY | | Director |
Edward D. Doherty | | |
/s/ RAYFORD T. REID | | Director |
Rayford T. Reid | | |
/s/ SHELBY E. ODELL | | Director |
Shelby E. Odell | | |
88
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors
Hiland Partners GP, LLC
We have audited the accompanying consolidated balance sheets of Hiland Partners, LP and subsidiaries, (the Partnership) as of December 31, 2005 and 2004, and the related consolidated statements of operations, cash flows, and changes in owners’ equity and comprehensive income for each of the three years in the period ended December 31, 2005. 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 audits 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 also 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 that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hiland Partners, LP and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, effective January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards No. 143 and changed its method of accounting for asset retirement obligations.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 24, 2006
F-2
HILAND PARTNERS, LP
Consolidated Balance Sheets
| | | | Predecessor | |
| | December 31, | | December 31, | |
| | 2005 | | 2004 | |
| | (in thousands,
except unit amounts) | |
ASSETS | | | | | | | | | |
Current assets: | | | | | | | | | |
Cash and cash equivalents | | | $ | 6,187 | | | | $ | 217 | | |
Accounts receivable: | | | | | | | | | |
Trade | | | 21,893 | | | | 9,663 | | |
Affiliates | | | 1,523 | | | | 758 | | |
| | | 23,416 | | | | 10,421 | | |
Inventories | | | — | | | | 153 | | |
Fair value of derivative assets | | | 868 | | | | — | | |
Other current assets | | | 395 | | | | 118 | | |
Total current assets | | | 30,866 | | | | 10,909 | | |
Property and equipment, net | | | 120,715 | | | | 37,075 | | |
Intangibles, net | | | 41,179 | | | | — | | |
Fair value of derivative assets | | | 181 | | | | — | | |
Other assets, net | | | 1,028 | | | | 1,191 | | |
Total assets | | | $ | 193,969 | | | | $ | 49,175 | | |
LIABILITIES AND OWNERS’ EQUITY | | | | | | | | | |
Current liabilities: | | | | | | | | | |
Accounts payable | | | $ | 13,324 | | | | $ | 5,649 | | |
Accounts payable—affiliates | | | 6,122 | | | | 2,998 | | |
Accrued liabilities | | | 1,126 | | | | 327 | | |
Current maturities of long-term debt | | | — | | | | 2,429 | | |
Total current liabilities | | | 20,572 | | | | 11,403 | | |
Commitments and contingencies | | | | | | | | | |
Long-term debt, net of current maturities | | | 33,784 | | | | 12,643 | | |
Asset retirement obligation | | | 1,024 | | | | 619 | | |
Owners’ equity | | | | | | | | | |
Predecessor stockholders’ equity | | | — | | | | 24,510 | | |
Limited partners’ interest: | | | | | | | | | |
Common unitholders (4,358,000 units issued and outstanding at December 31, 2005) | | | 110,027 | | | | — | | |
Subordinated unitholders (4,080,000 units issued and outstanding at December 31, 2005) | | | 25,126 | | | | — | | |
General partner interest | | | 2,676 | | | | — | | |
Unearned compensation | | | (289 | ) | | | — | | |
Accumulated other comprehensive income | | | 1,049 | | | | — | | |
Total owners’ equity | | | 138,589 | | | | 24,510 | | |
Total liabilities and owners’ equity | | | $ | 193,969 | | | | $ | 49,175 | | |
The accompanying notes are an integral part of these financial statements.
F-3
HILAND PARTNERS, LP
Consolidated Statements of Operations
| | | | Predecessor | |
| | Year Ended
December 31, | | Year Ended
December 31, | |
| | 2005 | | 2004 | | 2003 | |
| | (In thousands, except per unit amounts) | |
Revenues: | | | | | | | | | |
Midstream operations | | | | | | | | | |
Third parties | | | $ | 157,138 | | | $ | 95,019 | | $ | 73,666 | |
Affiliates | | | 5,246 | | | 3,277 | | 2,352 | |
Compression services, affiliate | | | 4,217 | | | — | | — | |
Total revenues | | | 166,601 | | | 98,296 | | 76,018 | |
Operating costs and expenses: | | | | | | | | | |
Midstream purchases (exclusive of items shown separately below) | | | 87,247 | | | 54,962 | | 40,760 | |
Midstream purchases—affiliate (exclusive of items shown separately below) | | | 45,842 | | | 27,570 | | 26,242 | |
Operations and maintenance | | | 7,359 | | | 4,933 | | 3,714 | |
Property impairment | | | — | | | — | | 1,535 | |
Depreciation, amortization and accretion | | | 11,112 | | | 4,127 | | 3,304 | |
(Gain) loss on sale of assets | | | — | | | (19 | ) | 34 | |
General and administrative expenses | | | 2,470 | | | 1,082 | | 770 | |
Total operating costs and expenses | | | 154,030 | | | 92,655 | | 76,359 | |
Operating income (loss) | | | 12,571 | | | 5,641 | | (341 | ) |
Other income (expense): | | | | | | | | | |
Interest and other income | | | 192 | | | 40 | | 10 | |
Amortization of deferred loan costs | | | (484 | ) | | (102 | ) | (24 | ) |
Interest expense | | | (1,942 | ) | | (702 | ) | (130 | ) |
Interest expense—affiliate | | | — | | | — | | (343 | ) |
Other income (expense), net | | | (2,234 | ) | | (764 | ) | (487 | ) |
Income (loss) from continuing operations | | | 10,337 | | | 4,877 | | (828 | ) |
Discontinued operations, net | | | — | | | 35 | | 246 | |
Income (loss) before cumulative effect of change in accounting principle | | | 10,337 | | | 4,912 | | (582 | ) |
Cumulative effect of change in accounting principle | | | — | | | — | | 1,554 | |
Net income | | | $ | 10,337 | | | $ | 4,912 | | $ | 972 | |
Less income attributable to predecessor | | | 493 | | | | | | |
Less general partner interest in net income | | | 464 | | | | | | |
Limited partners’ interest in net income | | | $ | 9,380 | | | | | | |
Net income per limited partners’ unit—basic | | | $ | 1.33 | | | | | | |
Net income per limited partners’ unit—diluted | | | $ | 1.32 | | | | | | |
Weighted average limited partners’ units outstanding—basic | | | 7,034 | | | | | | |
Weighted average limited partners’ units outstanding—diluted | | | 7,086 | | | | | | |
The accompanying notes are an integral part of these financial statements.
F-4
HILAND PARTNERS, LP
Consolidated Statements of Cash Flows
| | | | Predecessor | |
| | Year Ended | | Year Ended | |
| | December 31, | | December 31, | |
| | 2005 | | 2004 | | 2003 | |
| | (in thousands) | |
Cash flows from operating activities: | | | | | | | | | | | |
Net income | | | $ | 10,337 | | | | $ | 4,912 | | | $ | 972 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | |
Cumulative effect of change in accounting principle | | | — | | | | — | | | (1,724 | ) |
Depreciation and amortization | | | 11,083 | | | | 4,170 | | | 3,448 | |
Change in asset retirement obligation | | | 8 | | | | 23 | | | 25 | |
Amortization of deferred loan cost | | | 483 | | | | 102 | | | 24 | |
Unit based compensation | | | 28 | | | | — | | | — | |
Property impairments | | | — | | | | — | | | 1,535 | |
Loss (gain) on sale of assets | | | — | | | | (19 | ) | | 41 | |
(Increase) decrease in current assets, net of acquisition effects: | | | | | | | | | | | |
Accounts receivable | | | (17,507 | ) | | | (1,831 | ) | | (4,349 | ) |
Accounts receivable—affiliates | | | (765 | ) | | | (226 | ) | | (168 | ) |
Inventories | | | 153 | | | | 122 | | | — | |
Other current assets | | | (213 | ) | | | (113 | ) | | 5 | |
Increase (decrease) in current liabilities, net of acquisition effects: | | | | | | | | | | | |
Accounts payable | | | 782 | | | | 319 | | | 3,704 | |
Accounts payable—affiliates | | | 3,124 | | | | 482 | | | 664 | |
Accrued liabilities | | | 609 | | | | 16 | | | 287 | |
Net cash provided by operating activities | | | 8,122 | | | | 7,957 | | | 4,464 | |
Cash flows from investing activities: | | | | | | | | | | | |
Additions to property and equipment | | | (10,389 | ) | | | (5,326 | ) | | (5,389 | ) |
Payments for businesses acquired, net of cash | | | (64,559 | ) | | | — | | | (12,025 | ) |
Proceeds from disposals of property and equipment | | | 60 | | | | 36 | | | 128 | |
Net cash used in investing activities | | | (74,888 | ) | | | (5,290 | ) | | (17,286 | ) |
Cash flows from financing activities: | | | | | | | | | | | |
Borrowings from affiliate | | | — | | | | — | | | 13,598 | |
Repayments to affiliates | | | — | | | | — | | | (17,089 | ) |
Proceeds from initial public offering—net | | | 48,128 | | | | — | | | — | |
Redemption of common units from organizers | | | (6,278 | ) | | | — | | | — | |
Distributions to organizers | | | (3,851 | ) | | | — | | | — | |
Cash not contributed by organizers | | | (869 | ) | | | — | | | — | |
Payment of initial public offering costs | | | (2,249 | ) | | | — | | | — | |
Proceeds from long-term borrowings | | | 99,000 | | | | 500 | | | 17,000 | |
Payments on long-term borrowings | | | (89,167 | ) | | | (2,428 | ) | | — | |
Increase in deferred offering cost | | | — | | | | (1,012 | ) | | — | |
Debt issuance costs | | | (1,332 | ) | | | (6 | ) | | (297 | ) |
Cash distribution to controlling member for net assets of Hiland Partner, LLC | | | (27,768 | ) | | | — | | | — | |
Contribution by general partner | | | 7 | | | | — | | | — | |
Proceeds from secondary public offering—net | | | 66,071 | | | | — | | | — | |
Payment of secondary public offering costs | | | (607 | ) | | | — | | | — | |
Cash distribution to unitholders | | | (8,349 | ) | | | — | | | — | |
Net cash provided by (used in) financing activities | | | 72,736 | | | | (2,946 | ) | | 13,212 | |
Increase (decrease) for the year | | | 5,970 | | | | (279 | ) | | 390 | |
Beginning of year | | | 217 | | | | 496 | | | 106 | |
End of year | | | $ | 6,187 | | | | $ | 217 | | | $ | 496 | |
Supplementary information | | | | | | | | | | | |
Cash paid for interest, net of amounts capitalized | | | $ | 1,362 | | | | $ | 787 | | | $ | 239 | |
The accompanying notes are an integral part of these financial statements.
F-5
HILAND PARTNERS, LP
Consolidated Statements of Cash Flows (continued)
Non cash investing and financing activities: | | | |
Fair value of net assets acquired from Hiland Partners, LLC on February 15, 2005 in exchange for 252,927 common units and 1,433,251 subordinated units. | | | |
Accounts receivable and other current assets | | $ | 162 | |
Property and equipment | | 31,600 | |
Intangible assets | | 26,800 | |
Other assets | | 105 | |
Total assets acquired | | 58,667 | |
Less accounts payable and other current liabilities assumed | | (741 | ) |
Less current portion of long-term debt assumed | | (8,879 | ) |
Less asset retirement obligation assumed | | (398 | ) |
Fair value of net assets acquired | | $ | 48,649 | |
Transfer to shareholder on May 31, 2004 of oil and gas properties with a net book value of $2,489, accounts payable of $298 and asset retirement obligations of $50. | | | |
Transfer from property and equipment to inventory | | $ | 122 | |
Transfer from inventory to property and equipment | | (218 | ) |
Change in inventory, 2003 | | $ | (96 | ) |
Effective January 1, 2003 the company recorded the cumulative effect of SFAS No 143 for asset retirement obligation as follows: | | | |
Increase in property and equipment | | $ | 2,250 | |
Increase in asset retirement obligation | | (526 | ) |
Cumulative effect of accounting change | | $ | 1,724 | |
The accompanying notes are an integral part of these financial statements.
F-6
HILAND PARTNERS, LP
Consolidated Statement of Changes in Owners’ Equity and Comprehensive Income
For the Years Ended December 31, 2005, 2004 and 2003
| | | | Hiland Partners, LP | | | | | |
| | | | | | | | | | | | Accumulated | | | | | |
| | | | | | | | General | | | | Other | | | | | |
| | Predecessor | | Common | | Subordinated | | Partner | | Unearned | | Comprehensive | | | | Comprehensive | |
| | Equity | | Units | | Units | | Interest | | Compensation | | Income | | Total | | Income | |
| | (in thousands, except unit information) | |
Balance, January 1, 2003 | | | $ | 20,767 | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | — | | | $ | 20,767 | | | | | |
Net Income | | | 972 | | | | — | | | | — | | | | — | | | | — | | | | — | | | 972 | | | $ | 972 | | |
Balance, December 31, 2003 | | | 21,739 | | | | — | | | | — | | | | — | | | | — | | | | — | | | 21,739 | | | | | |
Net Income | | | 4,912 | | | | — | | | | — | | | | — | | | | — | | | | — | | | 4,912 | | | 4,912 | | |
Transfer of discontinued operations to parent company | | | (2,141 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | (2,141 | ) | | | | |
Balance, December 31, 2004 | | | 24,510 | | | | — | | | | — | | | | — | | | | — | | | | — | | | 24,510 | | | | | |
Assets not contributed to HilandPartners, LP | | | (9,972 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | (9,972 | ) | | | | |
Net income from January 1, 2005 through February 14, 2005 | | | 493 | | | | — | | | | — | | | | — | | | | — | | | | — | | | 493 | | | 493 | | |
Allocation of net parent investment to affiliated unitholders (467,073 common units and 2,646,749 subordinated units) | | | (15,031 | ) | | | 2,191 | | | | 12,418 | | | | 422 | | | | — | | | | — | | | — | | | — | | |
Contribution of certain net assets of Hiland Partners, LLC by owners (252,927 common units and 1,433,251 subordinated units) | | | — | | | | 7,092 | | | | 40,190 | | | | 1,367 | | | | — | | | | — | | | 48,649 | | | — | | |
Proceeds from initial public offering, net of underwriter discount (2,300,000 common units) | | | — | | | | 48,128 | | | | — | | | | — | | | | — | | | | — | | | 48,128 | | | — | | |
Offering costs of initial public offering | | | — | | | | (3,365 | ) | | | — | | | | — | | | | — | | | | — | | | (3,365 | ) | | — | | |
Redemption of Common Units from Organizers (300,000 common units) | | | — | | | | (6,278 | ) | | | — | | | | — | | | | — | | | | — | | | (6,278 | ) | | — | | |
Distributions to organizers | | | — | | | | (362 | ) | | | (3,489 | ) | | | — | | | | — | | | | — | | | (3,851 | ) | | — | | |
Cash distribution to controlling member for net assets of Hiland Partners, LLC | | | — | | | | (2,507 | ) | | | (24,473 | ) | | | (788 | ) | | | — | | | | — | | | (27,768 | ) | | — | | |
Contribution by general partner | | | — | | | | — | | | | — | | | | 7 | | | | — | | | | — | | | 7 | | | — | | |
Proceeds from secondary public offering, net of underwriter discount (1,630,000 common units) | | | — | | | | 64,682 | | | | — | | | | 1,389 | | | | — | | | | — | | | 66,071 | | | — | | |
Offering costs of secondary public offering | | | — | | | | (607 | ) | | | — | | | | — | | | | — | | | | — | | | (607 | ) | | — | | |
Periodic cash distributions | | | — | | | | (3,268 | ) | | | (4,896 | ) | | | (185 | ) | | | — | | | | — | | | (8,349 | ) | | — | | |
Issuance of restricted units (8,000 common units) | | | — | | | | 317 | | | | — | | | | — | | | | (317 | ) | | | — | | | — | | | — | | |
Unit based compensation | | | — | | | | — | | | | — | | | | — | | | | 28 | | | | — | | | 28 | | | — | | |
Change in fair value of derivatives | | | — | | | | — | | | | — | | | | — | | | | — | | | | 1,049 | | | 1,049 | | | 1,049 | | |
Net income from February 15, 2005 through December 31, 2005 | | | — | | | | 4,004 | | | | 5,376 | | | | 464 | | | | — | | | | — | | | 9,844 | | | 9,844 | | |
Comprehensive income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 11,386 | | |
Balance, December 31, 2005 | | | $ | — | | | | $ | 110,027 | | | | $ | 25,126 | | | | $ | 2,676 | | | | $ | (289 | ) | | | $ | 1,049 | | | $ | 138,589 | | | | | |
The accompanying notes are an integral part of this financial statement.
F-7
HILAND PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005 and 2004
(in thousands, except unit and per unit information or unless otherwise noted)
Note 1: Description of Business and Summary of Significant Accounting Policies
Description of Business
Hiland Partners, LP, a Delaware limited partnership (“we,” “us,” “our,” “HPLP” or “the Partnership”), was formed in October 2004 to acquire and operate certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously owned by Continental Gas, Inc. and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial public offering, Continental Gas, Inc. (“Predecessor” or “CGI”) contributed a substantial portion of its net assets to us.
CGI constitutes our predecessor. The transfer of ownership of net assets from CGI to us represented a reorganization of entities under common control and was recorded at historical cost. Accordingly, the financial statements include the historical operations of CGI prior to the transfer to us. CGI was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CRI”).
CGI operated in one segment, midstream, which involved the gathering, compressing, dehydrating, treating, and processing of natural gas and fractionating natural gas liquids, or NGLs. CGI historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland gathering system and our Bakken gathering system. Hiland Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken gathering system, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness.
CGI had minor interests in producing oil and gas properties located primarily in North Dakota. The properties were acquired over several years while CGI was a subsidiary of CRI. CGI did not intend to pursue the exploration for and development of oil and natural gas and, accordingly, conveyed its interest in these properties effective May 31, 2004 to CRI. Therefore, this activity is presented as discontinued operations.
In July 2004, CRI sold all of the issued and outstanding capital stock of CGI to the shareholders of CRI at fair value. The stock sale transaction was approved by all of the independent members of the Board of Directors of CRI, and the independent members of the Board of Directors were provided with an opinion as to the fairness of the stock sale transaction, from a financial point of view. CGI and CRI were previously consolidated and subsequently were affiliated corporations because of common ownership.
Principles of Consolidation
The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been eliminated. The consolidated financial statements include the net assets and operations of assets owned by CGI and Hiland Partners, LLC that were contributed to us concurrently with the completion of our initial public offering and also include the net assets and operations of Hiland Partners, LLC acquired effective September 1, 2005.
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Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
Cash and Cash Equivalents
For financial reporting, we consider all highly liquid investments with maturity of three months or less at date of purchase to be cash equivalents.
Accounts Receivable
The majority of our accounts receivable are due from companies in the oil and gas industry as well as the utility industry. Credit is extended based on evaluation of the customer’s financial condition. In certain circumstances, collateral, such as letters of credit or guarantees, is required. Accounts receivable are due within 30 days and are stated at amounts due from customers. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and rights of offset. Credit losses are charged to income when accounts are deemed uncollectible, determined on a case-by-case basis when we believe the required payment of specific amounts owed is unlikely to occur. These losses historically have been minimal. Therefore, an allowance for uncollectible accounts is not required.
Inventories
Inventories at December 31, 2004 consist primarily of compressors and associated equipment to be used in midstream operatons. Inventories are stated at the lower of cost or estimated net realizable value.
Concentration and Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and receivables. We place our cash and cash equivalents with high-quality institutions and in money market funds. We derive our revenue from customers primarily in the natural gas and utility industries. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.
Fair Value of Financial Instruments
Our financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives, accounts payable and bank debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.
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Long-Lived Assets
In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, we evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our management’s estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the volume of reserves providing asset cash flow and future NGL product and natural gas prices. The amount of reserves and drilling activity are dependent in part on natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including, but not limited to:
· changes in general economic conditions in regions in which the Partnership’s products are located;
· the availability and prices of NGL products and competing commodities;
· the availability and prices of raw natural gas supply;
· our ability to negotiate favorable marketing agreements;
· the risks that third party oil and gas exploration and production activities will not occur or be successful;
· our dependence on certain significant customers and producers of natural gas; and
· competition from other midstream service providers and processors, including major energy companies.
Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset.
In December 2003, as a result of volume declines at gathering facilities located in Texas, Mississippi and Wyoming, CGI recognized an impairment charge of $1.5 million. No impairment charges were recognized during each of the years ended December 31, 2005 and 2004.
Revenue Recognition
Revenues for sales of natural gas and NGLs are recognized at the time all gathering and processing activities are completed, the product is delivered and title is transferred. Revenues from oil and gas production (discontinued operations) are recorded in the month produced and title is transferred to the purchaser. Revenues related to our compression segment are recognized as monthly services are renderd under a four-year fixed-fee contract that we entered into concurrently with our intitial public offering.
Commodity Risk Management
We engage in price risk management activities in order to minimize the risk from market fluctuation in the price of natural gas. To qualify as a hedge, the price movements in the commodity derivatives must
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be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives which qualify as hedges are recognized in income when the underlying hedged physical transaction closes and are included in the consolidated statements of operations as revenues from midstream operations.
Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. SFAS No. 133 also provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that 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. Our 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.
Currently, our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in partners’ equity and reclassified into earnings in the same period in which the hedged transaction closes. The asset or liability related to the derivative instruments is recorded on the balance sheet as fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.
Comprehensive Income (Loss)
Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, unrealized gains and losses on marketable securities, foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on derivative financial instruments.
Pursuant to SFAS No. 133, we record deferred hedge gains and losses on our derivative financial instruments that qualify as cash flow hedges as other comprehensive income.
Property and Equipment
Our property and equipment are carried at cost. Depreciation and amortization of all equipment is determined under the straight-line method using various rates based on useful lives, 10 to 22 years for pipeline and processing plants, and 3 to 10 years for corporate and other assets. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Maintenance, repairs and minor replacements are expensed as incurred. Costs of replacements constituting improvement are capitalized.
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Intangible Assets
Intangible assets consist of the acquired value of existing contracts to sell natural gas and other NGLs and compression contracts, which do not have significant residual value. The contracts are being amortized over their estimated lives of ten years. We review intangible assets for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value based on the discounted probable cash flows of the intangible assets. No impairment of intangible assets has been recorded as of December 31, 2005. Intangible assets consisted of the following at December 31, 2005:
Gas sales contracts | | $ | 25,585 | |
Compression contracts | | 18,515 | |
| | 44,100 | |
Less accumulated amortization | | 2,921 | |
Intangible assets, net | | $ | 41,179 | |
There were no intangible assets prior to February 15, 2005. Estimated aggregate amortization expense for each of the five succeeding fiscal years is $4,410 from 2006 through 2010 and a total of $19,129 for all years thereafter.
Net Income per Limited Partners’ Unit
Net income per limited partners’ unit is computed based on the weighted-average number of common and subordinated units outstanding during the period. The computation of diluted net income per limited partner unit further assumes the diliutive effect of unit options. Net income per limited partners’ unit is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, and, for 2005, after deducting net income attributable to the Predecessor (before February 15, 2005), by both the basic and dilued weighted-average number of limited partnership units outstanding.
Environmental Costs
Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation. Liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. Recoveries of environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.
Income Taxes
As a partnership, we are not subject to income taxes. Therefore, there is no provision for income taxes included in our consolidated financial statements. Taxable income, gain, loss and deductions are allocated to the unitholders who are responsible for payment of any income taxes thereon.
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements.
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Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder’s tax attributes in our partnership is not available to us.
Transportation and Exchange Imbalances
In the course of transporting natural gas and NGLs for others, we may receive for redelivery different quantities of natural gas or NGLs than the quantities actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cashout provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. 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. As of December 31, 2005 and 2004, we had no imbalance receivables or payables.
Share-Based Compensation
Our general partner adopted the Hiland Partners, LP Long-Term Incentive Plan for employees and directors of our general partner and employees of its affiliates. The plan is intended to promote our interests and the interests of our general partner by providing to employees and directors of our general partner and its affiliates incentive compensation awards for superior performance that are based on units. The Plan is also contemplated to enhance the ability of our general partner, its affiliates or us to attract and retain the services of individuals who are essential for our growth and profitability and to encourage them to devote their best efforts to advancing our business. The long-term incentive plan currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units, and phantom units granted under the plan. No more than 225,000 of the 680,000 common units may be issued with respect to vested restricted or phantom units. The Plan will be administered by the compensation committee of our general partner’s board of directors. The plan will continue in effect until the earliest of (i) the date determined by the board of directors of our general partner; (ii) the date that common units are no longer available for payment of awards under the plan; or (iii) the tenth anniversary of the plan.
Our general partner’s board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. Our general partner’s board of directors or its compensation committee also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are listed at that time. No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant.
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We apply Accounting Principles Board Opinion No. 25 and related interpretations in accounting for our unit-based compensation awards. Accordingly, no compensation cost has been recognized for unit options granted in the accompanying consolidated financial statements. We had granted no unit options until adoption of our incentive unit option plan on February 15, 2005. Under the unit option grant agreement, granted options of common units will vest and become exercisable in one-third increments on the anniversary of the grant date over three years. Vested options are exercisable within the option’s contractual life of ten years after the grant date. The following pro forma data is calculated as if compensation cost for our unit-based compensation awards was determined based upon the fair value at the grant date consistent with the methodology prescribed under SFAS No. 123.
| | December 31, | |
| | 2005 | |
Net income as reported | | | $ | 10,337 | | |
Unit based compensation adjustment | | | (419 | ) | |
Pro forma net income | | | 9,918 | | |
Less income attributable to predecessor | | | 493 | | |
Less general partner interest | | | 447 | | |
Limited partner’s interest in pro forma net income | | | $ | 8,978 | | |
Net income per limited partner unit as reported, basic | | | $ | 1.33 | | |
Net income per limited partner unit as reported, diluted | | | $ | 1.32 | | |
Adjustment, basic | | | $ | (0.05 | ) | |
Adjustment, diluted | | | $ | (0.05 | ) | |
Proforma net income per limited partner unit, basic | | | $ | 1.28 | | |
Proforma net income per limited partner unit, diluted | | | $ | 1.27 | | |
Weighted average limited partner units outstanding, basic | | | 7,034,000 | | |
Weighted average limited partner units outstanding, diluted | | | 7,086,000 | | |
As of December 31, 2005, there were 167,500 options outstanding. The weighted-average fair value at grant date of the options granted during the year ended December 31, 2005 was $5.30 per unit. . The fair value of each option granted was estimated on the date of grant using the American Binomial option pricing model with the following weighted average assumptions used for grants in 2005: risk-free interest rate of 4.5 percent; 5.2 percent dividend yield; no assumed forfeitures; expected lives of 6.0 years; and volatility of 29.4 percent. During the year ended December 31, 2005 no options were exercised, forfeited or expired. The exercise price of the options granted equaled the market price of the units on the grant date. As of December 31, 2005, no options were exercisable. The pro forma amounts above are not likely to be representative of future years because there is no assurance that additional awards will be made each year.
The following table summarizes information about outstanding options as of December 31, 2005:
Range of Exercise Prices | | | | Weighted Number of Options Granted | | Weighted Average Remaining Years | | Average Exercise Price | |
$22.50 | | | 143,000 | | | | 9.1 | | | | $ | 22.50 | | |
$37.01 | | | 5,000 | | | | 9.6 | | | | $ | 37.01 | | |
$37.22 | | | 18,000 | | | | 9.7 | | | | $ | 37.22 | | |
$43.00 | | | 1,500 | | | | 9.8 | | | | $ | 43.00 | | |
| | | 167,500 | | | | 9.2 | | | | $ | 24.70 | | |
During the year ended December 31, 2005 we issued 8,000 restricted common units to non-employee board members of our general partner. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. The restricted units vest
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over a four year period from the date of issuance. The weighted average fair value at grant date was $39.69 per unit. Periodic distributions on the restricted units are held in trust by our general partner until the units vest. As a result of the restricted common units issued, our general partner contributed $7 to us to maintain its 2% ownership. We have recorded $317 as unearned compensation in owners’ equity based on the fair market value of the units on the date of grant. Unit-based compensation expense related to the restricted units was $28 for the year ended December 31, 2005.
Accounting for Asset Retirement Obligations
On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method and the liability is accreted to measure the change in liability due to the passage of time. The primary impact of this standard relates to dismantling and site restoration of certain of our plants and pipelines; and abandonment and plugging of oil and gas wells in which we participate (herein referenced as discontinued operations). Prior to SFAS 143, we had not recorded an obligation for these costs due to our assumption that the salvage value of the equipment would substantially offset the cost of dismantling the facilities and carrying out the necessary clean up and reclamation activities. The adoption of SFAS 143 on January 1, 2003, resulted in a net increase to Property and Equipment and Asset Retirement Obligations of approximately $2.3 million and $0.6 million, respectively, as a result of us separately accounting for salvage values and recording the estimated fair value of its dismantling, reclamation and plugging obligations on the balance sheet. The impact of adopting SFAS 143 was accounted for through a cumulative effect adjustment that amounted to $1.7 million increase to net income recorded on January 1, 2003.
The following table summarizes our activity related to asset retirement obligations:
Asset Retirement Obligation, January 1, 2003 | | $ | 526 | |
Plus: Accretion expense | | 25 | |
Additions for new assets | | 95 | |
Asset Retirement Obligation, December 31, 2003 | | 646 | |
Plus: Accretion expense | | 23 | |
Less: Transfer of discontinued operations | | (50 | ) |
Asset Retirement Obligation, December 31, 2004 | | 619 | |
Plus: Acquired from Hiland Partners, LLC on February 15, 2005 | | 398 | |
Accretion expense | | 27 | |
Less: Revisions | | (20 | ) |
Asset Retirement Obligation, December 31, 2005 | | $ | 1,024 | |
The effect of the change in accounting principle for 2003 was an increase to net income of $1,699, including $25 accretion of the asset retirement obligation.
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The following table presents the pro forma effect on net income for the year December 31, 2003 as if SFAS 143 had been adopted prior to January 1, 2003.
Net income, as reported | | $ | 972 | |
Discontinued operations, net | | (246 | ) |
Cumulative effect of change in accounting principle | | (1,554 | ) |
Loss from continuing operations, pro forma | | (828 | ) |
Discontinued operations, net | | 246 | |
Cumulative effect of change in accounting principle, discontinued operations | | (170 | ) |
Net loss, pro forma | | $ | (752 | ) |
Recent Accounting Pronouncements
SFAS No. 123, “Share-Based Payment”
In October 1995, the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004 (collectively, “SFAS 123R”). SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in financial statements and that cost will be measured based on the fair value of the equity or liability instruments issued. The effect of the standard will be to require entities to measure the cost of employee services received in exchange for stock or unit options based on the grant-date fair value of the award, and to recognize the cost over the period the employee is required to provide services for the award. We will apply SFAS 123R as of our first interim period beginning on January 1, 2006 and will use the permitted modified prospective method beginning as of the same date. Based on the unit options granted during the year ended December 31, 2005, we estimate our unit-based compensation expense to be $312, $134 and $22 for the years ended December 31, 2006, 2007 and 2008, respectively.
Note 2: Initial Formation and Contribution of Assets
In connection with our formation and our initial public offering on February 15, 2005, the assets and liabilities of CGI excluding certain working capital assets were contributed to us in exchange for 271,082 of our common units, after redemption of 195,991 common units, and 2,646,749 of our subordinated units. Existing bank debt of CGI was repaid from the proceeds of our initial public offering.
All of our initial assets were contributed by the former owners of CGI, Hiland Partners, LLC, and certain affiliates, including our general partner, in exchange for an aggregate of 720,000 common units and 4,080,000 subordinated units, a 2% general partner interest in us and all of our incentive distribution rights, which entitle the general partner to increasing percentages of the cash we distribute in excess of $0.495 per unit per quarter. The assets of CGI transferred to us are recorded at historical cost as it is considered to be a reorganization of entities under common control and CGI is considered our accounting predecessor. The acquisition of the assets of Hiland Partners, LLC was accounted for as a purchase and, as a result, these assets were recorded at their fair value at the time of purchase.
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The following table presents the assets and liabilities of our predecessor immediately prior to contributing assets to us, assets and liabilities contributed to us, and our predecessor’s assets and liabilities not contributed to us.
Continental Gas, Inc. (Predecessor)
Assets Contributed to Hiland Partners, LP
As of February 15, 2005
(in thousands)
| | Continental Gas, Inc. | | Net Assets | | Contributed to | |
| | (Predecessor) | | Not | | Hiland Partners, LP | |
| | February 14, 2005 | | Contributed | | February 15, 2005 | |
ASSETS | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | |
Cash and cash equivalents | | | $ | 869 | | | | $ | 869 | | | | $ | — | | |
Accounts Receivable | | | 10,521 | | | | 9,101 | | | | 1,420 | | |
Inventories | | | 153 | | | | — | | | | 153 | | |
Other current assets | | | 291 | | | | 2 | | | | 289 | | |
Total Current Assets | | | 11,834 | | | | 9,972 | | | | 1,862 | | |
Property and equipment, at cost, net | | | 36,805 | | | | — | | | | 36,805 | | |
Other assets, net | | | 3,388 | | | | — | | | | 3,388 | | |
Total assets | | | 52,027 | | | | 9,972 | | | | 42,055 | | |
LIABILITIES | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | |
Accounts payable | | | 11,703 | | | | — | | | | 11,703 | | |
Accrued liabilities | | | 700 | | | | — | | | | 700 | | |
Current maturities of long term debt | | | 2,429 | | | | — | | | | 2,429 | | |
Total current liabilities | | | 14,832 | | | | — | | | | 14,832 | | |
Commitments and contingencies | | | | | | | | | | | | | |
Long term debt, net of current maturities | | | 11,570 | | | | — | | | | 11,570 | | |
Asset retirement obligation | | | 622 | | | | — | | | | 622 | | |
Total liabilities | | | 27,024 | | | | — | | | | 27,024 | | |
NET ASSETS | | | $ | 25,003 | | | | $ | 9,972 | | | | $ | 15,031 | | |
In consideration for the transfer, the owners of CGI received 467,073 of our common units and 2,646,749 of our subordinated units. Immediately following the closing of the offering, 195,991 of the common units were redeemed for approximately $4.1 million.
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The following table presents the assets and liabilities of Hiland Partners, LLC as of February 14, 2005, the assets excluded from the acquisition, and the fair value of the assets acquired.
Hiland Partners, LLC
Assets Contributed to Hiland Partners, LP
As of February 15, 2005
(in thousands)
| | | | Net Assets | | Contributed to | | | |
| | Hiland Partners, LLC | | Not | | Hiland Partners, LP | | Fair | |
| | February 14, 2005 | | Contributed | | February 15, 2005 | | Value | |
ASSETS | | | | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | | $ | 964 | | | | $ | 964 | | | | $ | — | | | $ | — | |
Accounts Receivable | | | 2,619 | | | | 2,503 | | | | 116 | | | 116 | |
Other current assets | | | 56 | | | | 10 | | | | 46 | | | 46 | |
Total Current Assets | | | 3,639 | | | | 3,477 | | | | 162 | | | 162 | |
Property and equipment, at cost, net | | | 50,063 | | | | 29,858 | | | | 20,205 | | | 31,600 | |
Intangible Assets | | | — | | | | — | | | | — | | | 26,800 | |
Other assets, net | | | 194 | | | | 89 | | | | 105 | | | 105 | |
Total assets | | | 53,896 | | | | 33,424 | | | | 20,472 | | | 58,667 | |
LIABILITIES | | | | | | | | | | | | | | | |
Current liabilities: | | | | | | | | | | | | | | | |
Accounts payable | | | 5,048 | | | | 4,372 | | | | 676 | | | 676 | |
Accrued liabilities | | | 95 | | | | 30 | | | | 65 | | | 65 | |
Current maturities of long term debt | | | 11,100 | | | | 2,221 | | | | 8,879 | | | 8,879 | |
Total current liabilities | | | 16,243 | | | | 6,623 | | | | 9,620 | | | 9,620 | |
Commitments and contingencies | | | — | | | | — | | | | — | | | — | |
Long term debt, net of current maturities | | | 24,253 | | | | 24,253 | | | | — | | | — | |
Asset retirement obligation | | | 398 | | | | — | | | | 398 | | | 398 | |
Total liabilities | | | 40,894 | | | | 30,876 | | | | 10,018 | | | 10,018 | |
NET ASSETS | | | $ | 13,002 | | | | $ | 2,548 | | | | $ | 10,454 | | | $ | 48,649 | |
In consideration for the transfer:
a. Non-managing members received 247,868 of our common units and 1,404,586 of our subordinated units. Immediately following the closing of the offering, 104,009 of the common units were redeemed for approximately $2.2 million.
b. The managing member of Hiland Partners, LLC received 5,059 of our common units and 28,665 of our subordinated units, none of which were redeemed.
As a part of the transactions, owners of CGI, Hiland Partners, LLC and certain members of our management received an aggregate of 138,776 equivalent units of our General Partner, representing substantially all of the ownership of the general partner and a 2% equity ownership in us.
The proceeds of the public offering were used to: redeem an aggregate of 300,000 common units from former owners for $6.3 million; repay $14.0 million in debt owed by CGI and $8.9 million in debt contributed from Hiland Partners, LLC; pay the remaining $2.2 million of expenses associated with the offering and formation transactions; pay $0.6 million of debt issuance costs related to the credit facility;
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distribute $3.9 million to the former owners of Hiland Partners, LLC in reimbursement of certain capitalized expenditures related to the assets of Hiland Partners, LLC that were contributed to us; and replenish approximately $12.2 million of working capital.
Note 3: Acquisitions
On September 26, 2005, we completed our acquisition of Hiland Partners, LLC, an Oklahoma limited liability company, for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. The effective date of the acquisition was September 1, 2005. Hiland Partners, LLC’s principal asset was the Bakken gathering system located in Richland County, Montana. At the time of the acquisition, the Bakken gathering system consisted of approximately 256 miles of gas gathering pipeline, a natural gas processing plant, two compressor stations and one fractionation facility. This acquisition was a growth opportunity for us in the rocky mountain region where we already have operations that are very accretive. The Bakken processing plant and a portion of the gathering system became operational on November 8, 2004.
To facilitate the closing of the acquisition, we amended our senior secured revolving credit facility to increase our borrowing capacity under the facility from $55.0 million to $125.0 million, consisting of a $117.5 million acquisition facility and a $7.5 million working capital facility. The credit facility’s maturity date remained the same, February 15, 2008. The current interest rate ranges from LIBOR plus 150 to 275 basis points depending on leverage coverage. We used a portion of this increased capacity to fund the acquisition.
To the extent of our non-controlling ownership, the acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations.” As of the date of our acquisition, Hiland Partners, LLC was an entity partially owned by a controlling member of our general partner. Accordingly, 49% of the Bakken gathering system assets, for which estimated fair value was in excess of historical basis, have been recorded at historical cost and 51% of the Bakken gathering system assets have been recorded at fair value. A cash distribution of $27.8 million made to the controlling member as reported in the statement of owners’ equity reflects the difference in the purchase price paid to the controlling member of our general partner and his cost basis in the net assets of Hiland Partners, LLC. The fair value of the assets acquired has also been reduced by imputed interest expense from September 1, 2005, the effective date of the acquisition, through the closing date, September 26, 2005. The following table presents the resulting allocation to the net assets acquired and liabilities assumed at the effective date of acquisition:
Cash and cash equivalents | | $ | 300 | |
Accounts receivable | | 3,708 | |
Other current assets | | 20 | |
Property, plant and equipment | | 49,873 | |
Customer contracts | | 17,589 | |
Total assets acquired | | 71,490 | |
Accounts payable | | (6,217 | ) |
Accrued liabilities | | (125 | ) |
Total liabilities assumed | | (6,342 | ) |
Net assets of Hiland Partners, LLC | | 65,148 | |
Imputed interest expense | | (289 | ) |
Purchase price of net assets of Hiland Partners, LLC less distribution to the controlling member | | $64,859 | |
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The operations of the Bakken gathering system are included in the statement of operations and statement of cash flows from September 1, 2005 forward.
The acquisition of Hiland Partners, LLC was effective September 1, 2005 and the initial acquisition of assets from Hiland Partners, LLC discussed in note 13 occurred on February 15, 2005. Had the acquisitions been made effective January 1, 2004, the operations of the assets acquired from Hiland Partners, LLC would have been included in our consolidated financial statements for each subsequent period with the following unaudited pro forma impact on the consolidated statements of operations. The unaudited pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed dates.
| | For the Year Ended
December 31, | |
| | 2005 | | 2004 | |
Revenues as reported | | $ | 166,601 | | $ | 98,296 | |
Revenues from Hiland Partners, LLC | | 18,648 | | 14,335 | |
Pro forma revenues | | $ | 185,249 | | $ | 112,631 | |
Net income as reported | | $ | 10,337 | | $ | 4,912 | |
Additional loss from acquired interest | | (4,176 | ) | (1,867 | ) |
Pro forma net income | | $ | 6,161 | | $ | 3,045 | |
Less income attributable to predecessor | | 493 | | | |
Less general partner interest in proforma net income | | 378 | | | |
Limited partners’ interest in proforma net income | | $ | 5,290 | | | |
Proforma net income per limited partner unit, basic | | $ | 0.75 | | | |
Proforma net income per limited partner unit, diluted | | $ | 0.75 | | | |
Weighted average limited partner units outstanding, basic | | 7,034,000 | | | |
Weighted average limited partner units outstanding, diluted | | 7,086,000 | | | |
On July 31, 2003, we acquired the Carmen Gathering System ("Carmen") located in western Oklahoma from Great Plains Pipeline Company for $15.0 million. After various adjustments and other reductions in the purchase and sale agreement, the net cost was $12.0 million. Funding for the acquisition was obtained under our credit agreement with CRI. The allocation of the purchase price was based on fair values of the assets as follows:
Land | | $ | 120 | |
Pipeline | | 11,833 | |
Other equipment | | 72 | |
Total | | $ | 12,025 | |
The operations of Carmen are included in the statement of operations and statement of cash flows from August 1, 2003 forward.
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The unaudited pro forma financial information set forth below for the year ended December 31, 2003 assumes the acquisition of Carmen by CGI occurred on January 1, 2003. The unaudited pro forma financial information is presented for information only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition be consummated at that time:
Revenues | | $ | 90,552 | |
Loss from continuing operations | | $ | 1,963 | |
Net loss | | $ | 163 | |
Note 4: Property and Equipment
| | As of December 31, | |
| | 2005 | | 2004 | |
Land | | $ | 225 | | $ | 127 | |
Construction in progress | | 3,676 | | — | |
Pipeline and plants | | 122,927 | | 53,745 | |
Compression and water injection equipment | | 19,264 | | — | |
Other | | 1,689 | | 2,209 | |
| | 147,781 | | 56,081 | |
Less: accumulated depreciation and amortization | | 27,066 | | 19,006 | |
| | $ | 120,715 | | $ | 37,075 | |
Construction in progress at December 31, 2005, associated with our Badlands expansion, includes $32 of capitalized interest. Depreciation charged to expense, including discontinued operations, totaled $8,162, $4,170, and $3,448 for the years ended December 31, 2005, 2004 and 2003, respectively.
Note 5: Derivatives
During the quarter ended December 31, 2005 we entered into certain financial swap instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate only to forecasted sales in 2006 and 2007. We entered into these instruments to hedge the forecasted natural gas sales against the variability in expected future cash flows attributable to changes in market prices. Under these contractual swap agreements with our counterparties, we receive a fixed price and pay a floating price based on certain indices for the relevant contract period as the underlying natural gas is sold.
We formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Highly effective is deemed to be a correlation range from 80% to 125% of the change in cash flows of the derivative in offsetting the cash flows of the hedged transaction. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, we will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. We assess effectiveness using regression analysis and ineffectiveness using the dollar offset method.
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Derivatives are recorded on our Consolidated Balance Sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value are recognized in owners’ equity as Accumulated Other Comprehensive Income and reclassified to earnings when the underlying hedged physical transaction closes. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. During the year ended December 31, 2005 we recorded $1,049 in Accumulated Other Comprehensive Income. At December 31, 2005, on our Consolidated Balance Sheet, we reflected a current derivative asset of $868 and a non-current derivative asset of $181. If the fair values of the current derivative assets remain constant over the next twelve-month period, we will recognize $868 in earnings as these contracts settle. The non-current derivative asset of $181 will be recognized as earnings in later periods. Actual amounts that will be reclassified will vary as a result of future changes in prices. Ineffective gains or losses are recorded in income while the hedge contract is open and may increase or decrease until settlement of the contract. Realized gains and losses on these instruments are reflected in the contract month being hedged as an adjustment to our midstream revenue. We calculated no significant ineffectiveness on our hedges during the year ended December 31, 2005 since the index in our swap contract is the same index in our sales contracts.
As of December 31, 2005, we had the following natural gas volumes hedged for the periods indicated:
| | | | Average | | Fair Value | |
Production Period | | | | Volume | | Fixed Price | | Asset | |
(Calendar year) | | (MMBtu) | | (per MMBtu) | | (in thousands) | |
2006 | | 1,080,000 | | | $ | 8.94 | | | | $ | 868 | | |
2007 | | 1,350,000 | | | $ | 8.03 | | | | 181 | | |
| | | | | | | | | $ | 1,049 | | |
| | | | | | | | | | | | | | | |
Note 6: Long-Term Debt
| | As of December 31, | |
| | 2005 | | 2004 | |
Note payable—bank | | $ | 33,784 | | $ | 15,072 | |
Less: current portion | | — | | 2,429 | |
Long-term portion | | $ | 33,784 | | $ | 12,643 | |
(a) On October 22, 2003, we closed a $35.0 million secured credit facility consisting of a senior secured term loan facility of up to $25.0 million, and a senior revolving credit facility of up to $10.0 million. Prior to closing this credit facility, we had borrowed funds from CRI under its credit facility. The initial advance under the term loan facility was $17.0 million, the majority of which was paid to CRI to reduce the outstanding balance on its credit facility. No funds were initially advanced under the revolving loan facility. This loan originally matured September 30, 2006, but was subsequently repaid from the proceeds on our initial public offering in February 2005.
(b) On February 15, 2005, concurrently with the closing of our initial public offering, we entered into a three-year $55.0 million senior secured revolving credit facility. MidFirst Bank, a federally chartered savings association located in Oklahoma City, Oklahoma, is a lender and serves as administrative agent under this facility. The credit facility consisted of a $47.5 million senior secured revolving credit facility to be used for funding acquisitions and other capital expenditures, issuance of letters of credit and general corporate purposes (the “revolving acquisition facility”) and a $7.5 million senior secured revolving credit facility to be used for working capital and to fund distributions (the “revolving working capital facility”).
On September 26, 2005, concurrently with the acquisition of Hiland Partners, LLC, we amended our senior secured revolving credit facility to increase our borrowing capacity under the facility from
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$55.0 million to $125.0 million, consisting of a $117.5 million acquisition facility and a $7.5 million working capital facility. On September 26, 2005, we incurred $93.7 million of indebtedness under the credit facility in connection with our acquisition of Hiland Partners, LLC.
On November 21, 2005 we completed our secondary offering. We used $65.2 million of the $66.1 million net procceds from the offering to repay a majority of the credit facility borrowings we used to fund the Bakken acquisition. The credit facility will mature in February 2008. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable. The remaining acquisition facility available to us under the credit agreement at December 31, 2005 was $83.7 million. All of the $7.5 million working capital facility was available to us at December 31, 2005.
Our obligations under the credit facility are collateralized by substantially all of our assets and guaranteed by us and all of our subsidiaries, other than our operating company, Hiland Operating, LLC, which is the borrower under the credit facility. The credit facility is non-recourse to our general partner.
Indebtedness under the credit facility will bear interest, at our option, at either (i) an Alternate Base Rate plus an applicable margin ranging from 50 to 175 basis points per annum or (ii) LIBOR plus an applicable margin ranging from 150 to 275 basis points per annum based on our ratio of total debt to EBITDA. The Alternate Base Rate is a rate per annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect on such day plus one-half of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to 1.0%. An unused commitment fee ranging from 30 to 50 basis points per annum based on our ratio of total debt to EBITDA will be payable on the unused portion of the credit facility.
The credit facility imposes certain requirements, including: prohibition against distribution to unitholders if, before or after the distribution, a potential default or an event of default as defined in the agreement would occur; limitations on our ability to incur debt, grant liens, make loans, acquisitions, and investments, change the nature of our business, enter into a merger or consolidation, or sell assets, amend material agreements; and covenants that require maintenance of certain levels of tangible net worth, EBITDA to interest expense ratio, and debt to EBITDA ratio. If an event of default exists under the agreement, the lenders will be able to accelerate the maturity of the debt and exercise other rights and remedies. As of December 31, 2005, we were in compliance with all of the covenants associated with our credit facility.
Note 7: Commitments and Contingencies
On November 8, 2005, we entered into a new 15-year definitive gas purchase agreement with Continental Resources, Inc. under which we will gather, treat and process additional natural gas, which is produced as a by-product of Continental Resources’ secondary oil recovery operations, in the areas specified by the contract. In return, we will receive 50% of the proceeds attributable to residue gas and natural gas liquids sales as well as certain fixed fees associated with gathering and treating the natural gas, including a $0.60 per Mcf fee for the first 36 Bcf of natural gas gathered. The board of directors, as well as the conflicts committee of the board of directors of our general partner, has approved the agreement.
In order to fulfill our obligations under the agreement, we intend to expand our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will include the construction of a 40,000 Mcf/d nitrogen rejection plant and the expansion of our existing Badlands field gathering infrastructure. The expansion project, which is targeted for completion in the 4th quarter of 2006, is expected to cost approximately $40 million, which we intend to fund using our existing bank credit facility. Moreover, we expect to spend an additional $9.5 million in 2007 to expand the system.
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We have executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month through December 2007 with weighted average fixed prices per MMBtu of $4.47 and $4.49, respectively, for years 2006 through 2007. We also have fixed price physical forward sales contracts to sell 1) approximately 50,000 MMBtu of natural gas per month from October 2005 through December 2006 with weighted average fixed prices per MMBtu of $9.52 and 2) approximately 50,000 MMBtu of natural gas per month from January 2007 through December 2007 with weighted average fixed prices per MMBtu of $9.13. Such contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.
We maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees compensation. During 2005, 2004 and 2003 contributions to the plan were 5.0% of eligible employees’ compensation. Expense for the years ended December 31, 2005, 2004 and 2003 was $111, $70, and $54, respectively.
We jointly participate with other affiliated companies in a self-insurance pool (the “Pool”) covering health and workers’ compensation claims made by employees up to the first $150 and $500, respectively, per claim. Any amounts paid above these are reinsured through third party providers. Premiums charged to the Partnership are based on estimated costs per employee of the Pool. In December, 2005 we incurred an additional $104 representing our share of additional premiuims due under the self-insurance plan. Property and general liability insurance is maintained through third-party providers with a $100 deductible on each policy.
We lease office space from a related entity. We lease certain facilities,vehicles and equipment under operating leases, most of which contain annual renewal options. For the years ended 2005, 2004 and 2003, rent expense was $224, $198 and $174, respectively, under these leases. At December 31, 2005, including leases renewed and entered into subsequent to year end but prior to financial statement issuance, the minimum future rental commitments under operating leases having non-cancelable lease terms in excess of one year, including leases from related parties, total:
| | Amount | |
2006 | | | $ | 97 | | |
2007 | | | 109 | | |
2008 | | | 108 | | |
2009 | | | 75 | | |
2010 | | | 13 | | |
Thereafter | | | 40 | | |
Total | | | $ | 442 | | |
We also entered into two separate one-year lease agreements for two compressors for our Bakken facilities, both of which will terminate by December 31, 2006. Payments under the leases will be $357 in the year 2006.
The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state or local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations.
We are a party to various regulatory proceedings and may from time to time be a party to litigation that we believe will not have a materially adverse impact on our financial condition, results of operations or cash flows.
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Note 8: Significant Customers and Suppliers
All of our revenues are domestic revenues. The following table presents our top midstream customers as a percent of total revenue for the periods indicated:
| | For the Year Ended
December 31, | |
| | 2005 | | 2004 | | 2003 | |
Customer 1 | | | 23 | % | | | — | | | | — | | |
Customer 2 | | | 16 | % | | | 29 | % | | | 19 | % | |
Customer 3 | | | 13 | % | | | 33 | % | | | 28 | % | |
Customer 4 | | | 8 | % | | | 10 | % | | | 7 | % | |
Customer 5 | | | 5 | % | | | 5 | % | | | 9 | % | |
Customer 6 | | | 6 | % | | | — | | | | — | | |
Customer 7 | | | — | | | | — | | | | 17 | % | |
All of our purchases are from domestic sources. The following table presents our top midstream suppliers as a percent of total midstream purchases for the periods indicated:
| | For the Year Ended
December 31, | |
| | 2005 | | 2004 | | 2003 | |
Supplier 1 (affiliated company) | | | 34 | % | | | 33 | % | | | 37 | % | |
Supplier 2 | | | 28 | % | | | 33 | % | | | — | | |
Supplier 3 | | | 13 | % | | | 17 | % | | | 18 | % | |
Supplier 4 | | | 6 | % | | | — | | | | — | | |
Supplier 5 | | | — | | | | — | | | | 20 | % | |
Note 9: Related Party Transactions
We purchase natural gas and NGLs from affiliated companies. Purchases of product totaled $45.8 million, $27.6 million, and $26.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. We sell natural gas and NGLs to affiliated companies. Sales of product totaled $5.2 million, $3.3 million, and $2.4 million for the years ended December 31, 2005, 2004 and 2003, respectively. Compression revenues from affiliates were $4.2 million for the year ended December 31, 2005. There were no compression revenues in the years 2004 or 2003.
Accounts receivable affiliates of $1,523 and $758 at December 31, 2005 and 2004, respectively, includes $1,451 and $682 from one affiliate for midstream sales.
Accounts payable affiliates of $6,122 at December 31, 2005 includes $5,684 due to one affiliate for midstream purchases. Accounts payable affiliates of $2,998 at December 31, 2004 is all payable to one affiliate for midstream purchases.
We utilize affiliated companies to provide services to our plants and pipelines and certain administrative costs. The total amount paid to these companies was $336, $183, and $193 during the years ended December 31, 2005, 2004 and 2003, respectively.
We lease office space under operating leases directly or indirectly from an affiliate. Rents paid associated with these leases totaled $75, $51, and $47 for the years ended December 31, 2005, 2004 and 2003, respectively.
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Note 10: Business Segments
On February 15, 2005, certain assets and liabilities of Hiland Partners, LLC were contributed to us in conjunction with our initial public offering. As a result of this transaction, we have distinct operating segments for which additional financial information must be reported. Prior to February 15, 2005, we did not have operating segments. Our operations are now classified into two reportable segments:
(1) Midstream, which is the gathering, compressing, dehydrating, treating and processing of natural gas and fractionating NGLs.
(2) Compression, which is providing air compression and water injection services for CRI’s oil and gas secondary recovery operations that are ongoing in North Dakota.
We evaluate the performance of our segments and allocate resources to them based on operating income. Our operations are conducted in the United States.
Midstream assets totaled $158,295 at December 31, 2005. Assets attributable to compression operations totaled $34,894. Midstream assets attributable to the Bakken acquisition effective September 1, 2005 were $64,559. Other capital expenditures of $10,389 for the year ended December 31, 2005 were all related to the midstream segment. The tables below present information about operating income for the reportable segments for the year ended December 31, 2005.
| | For the Year Ended December 31, 2005 | |
| | Midstream | | Compression | | Total | |
Revenues | | | $ | 162,384 | | | | $ | 4,217 | | | $ | 166,601 | |
Operating costs and expenses: | | | | | | | | | | | |
Midstream purchases (exclusive of items shown separately below) | | | 133,089 | | | | — | | | 133,089 | |
Operations and maintenance | | | 6,800 | | | | 559 | | | 7,359 | |
Depreciation, amortization and accretion | | | 7,921 | | | | 3,191 | | | 11,112 | |
General and administrative expenses | | | 2,407 | | | | 63 | | | 2,470 | |
Total operating costs and expenses | | | 150,217 | | | | 3,813 | | | 154,030 | |
Income from operations | | | $ | 12,167 | | | | $ | 404 | | | 12,571 | |
Other income (expense): | | | | | | | | | | | |
Interest and other income | | | | | | | | | | 192 | |
Amortization of deferred loan costs | | | | | | | | | | (484 | ) |
Interest expense | | | | | | | | | | (1,942 | ) |
Total other income (expense) | | | | | | | | | | (2,234 | ) |
Net income | | | | | | | | | | $ | 10,337 | |
Note 11: Discontinued Operations
During the first quarter of 2004, the Partnership determined it would no longer pursue its interests in direct production of oil and gas. Amounts for oil and gas income and expense are presented in these statements as discontinued operations. Effective May 31, 2004, the Partnership transferred all its interests in its oil and gas properties to CRI.
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A summary of oil and gas operations follows:
| | For the Years Ended | |
| | December 31, | |
| | 2004 | | 2003 | |
Revenues | | | $ | 266 | | | | $ | 604 | | |
Expenses | | | (165 | ) | | | (351 | ) | |
Depreciation and amortization | | | (66 | ) | | | (170 | ) | |
Loss on asset sales | | | — | | | | (7 | ) | |
Change in accounting principle | | | — | | | | 170 | | |
Net income | | | $ | 35 | | | | $ | 246 | | |
The transfer, recorded at carrying value, included the following:
| | Amount | |
Leasehold costs | | $ | 67 | |
Capitalized intangible costs | | 3,063 | |
Lease and well equipment | | 1,689 | |
Asset retirement cost | | 41 | |
Accounts payable | | (298 | ) |
Accumulated amortization | | (1,623 | ) |
Accumulated depreciation | | (748 | ) |
Asset retirement obligation | | (50 | ) |
| | $ | 2,141 | |
The Partnership followed the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved recoverable oil and gas reserves.
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Note 12: Selected Quarterly Financial Data—Unaudited
The following is a summary of selected quarterly financial data for the years ended December 31, 2005 and 2004.
| | 2005 Quarter | |
| | 1st | | 2nd | | 3rd | | 4th | |
Revenues | | $ | 25,778 | | $ | 30,603 | | $ | 41,925 | | $ | 68,295 | |
Operating income | | 1,968 | | 1,962 | | 3,282 | | 5,359 | |
Net income | | 1,636 | | 1,879 | | 2,684 | | 4,138 | |
Income attributable to predecessor | | 493 | | — | | — | | — | |
General partner interest in net income | | 23 | | 37 | | 72 | | 332 | |
Limited partners’ interest in net income | | $ | 1,120 | | $ | 1,842 | | $ | 2,612 | | $ | 3,806 | |
Net income per limited partner unit—basic and diluted | | $ | 0.16 | | $ | 0.27 | | $ | 0.38 | | $ | 0.50 | |
| | 2004 Quarter | |
| | 1st | | 2nd | | 3rd | | 4th | |
Revenues | | $ | 21,050 | | $ | 23,849 | | $ | 25,387 | | $ | 28,010 | |
Operating income | | 933 | | 1,126 | | 1,089 | | 2,493 | |
Income from continuing operations | | 752 | | 937 | | 898 | | 2,290 | |
Net income | | $ | 767 | | $ | 1,008 | | $ | 847 | | $ | 2,290 | |
Note 13: Net Income per Limited Partners’ Unit
The computation of net income per limited partners’ unit is based on the weighted-average number of common and subordinated units outstanding during the period. Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners, after deducting the general partner’s 2% interest and incentive distributions, and after deducting net income attributable to the Predecessor (before February 15, 2005), by the weighted-average number of limited partnership units outstanding. The following is a reconciliation of the limited partner units used in the calculations of income per limited partner unit—basic and income per limited partner unit—diluted assuming dilution for the year ended December 31, 2005:
| | Income | | | | | |
| | Available to | | | | | |
| | Limited | | Limited | | | |
| | Partners | | Partner Units | | Per Unit | |
| | (Numerator) | | (Denominator) | | Amount | |
For the Year ended December 31, 2005: | | | | | | | | | | | | | |
Income per limited partner unit—basic: | | | | | | | | | | | | | |
Income available to limited partners | | | $ | 9,380 | | | | | | | | $ | 1.33 | | |
Weighted average limited partner units outstanding | | | | | | | 7,034,000 | | | | | | |
Income per limited partner unit—diluted: | | | | | | | | | | | | | |
Unit Options | | | | | | | 52,000 | | | | | | |
Income available to limited partners plus assumed conversions | | | $ | 9,380 | | | | 7,086,000 | | | | $ | 1.32 | | |
Note 14: Partners’ capital
Our unitholders (limited partners) have only limited voting rights on matters affecting our operations and activities and, therefore, limited ability to influence our management’s decisions regarding our business. Unitholders did not select our general partner or elect the board of directors of our general partner and effectively have no right to select our general partner or elect its board of directors in the future. Unitholders’ voting rights are further restricted by our 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
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the 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 be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting a unitholders’ ability to influence the manner or direction of our management
Our Partnership Agreement requires that we distribute all of our cash on hand at the end of each quarter, less reserves established at our general partner’s discretion. We refer to this as “available cash.” The amount of available cash may be greater than or less than the minimum quarterly distributions. In general, we will pay any cash distribution made each quarter in the following manner:
· first, 98% to the common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.45 plus any arrearages from prior quarters;
· second, 98% to the subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.45; and
· third, 98% to all units pro rata, and 2% to our general partner, until each unit has received a distribution of $0.495.
If cash distributions per unit exceed $0.495 in any quarter, our general partner will receive increasing percentages, up to a maximum of 50% of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.”
The distributions on the subordinated units may be reduced or eliminated if necessary to ensure the common units receive their minimum quarterly distribution. Subordinated units will not accrue arrearages. The subordination period will end once we meet certain financial tests, but not before March 31, 2010. These financial tests require us to have earned and paid the minimum quarterly distribution on all of our outstanding units for three consecutive four-quarter periods. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
On April 25, 2005, we announced our first regular cash distribution in 2005 of $0.225 per unit, based on the minimum quarterly cash distribution of $0.45 prorated for the period since the initial public offering on February 15, 2005. The distribution to all common, subordinated and general partner units was paid May 13, 2005, to all unitholders of record on May 5, 2005. The aggregate amount of the distribution was $1.6 million.
On July 26, 2005, we announced a regular cash distribution of $0.4625 per unit for the second quarter of 2005. The distribution to all common, subordinated and general partner units was paid on August 12, 2005 to all unitholders of record on August 5, 2005. The aggregate amount of the distribution was $3.2 million.
On October 25, 2005, we announced a regular cash distribution of $0.5125 per unit for the third quarter of 2005. The distribution to all common, subordinated and general partner units was paid on November 14, 2005 to all unitholders of record on November 4, 2005. The aggregate amount of the distribution was $3.5 million. As provided for in our Partnership Agreement, our general partner is entitled to receive increasing percentages, up to a maximum of 50% of the cash distributed in excess of $0.495 in any quarter as “incentive distributions.” This distribution of $0.5125 per unit exceeds the $0.495 per unit by $0.0175. Accordingly, our general partner received an additional 15% of the excess, or $18.
Note 15: Subsequent Events
In February 2006, we executed four separate swap contracts relating to portions of our natural gas liquids (NGLs) sales of propane, normal butane, isobutane and normal gasoline from our Matli gathering
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system for the fixed prices noted below. Under the NGL swap contracts, we will either pay or receive the difference between the fixed prices below and the arithmetic average of the mean of the daily high and low prices for either Mapco propane, normal butane, isobutane or normal gasoline for those issues of Oil Price Information Service (“OPIS”) in the table U.S. & Canada Spot LP-Gas Weekly Averages under the heading Conway/Group 140 Spot Gas Liquids Prices published for the applicable pricing period(s). As a result, we have hedged a portion of our expected exposure to natural gas liquids prices in 2006, 2007 and 2008 at our Matli gathering system. The following table provides information about these financial derivative instruments for the periods indicated:
| | Monthly | | Fixed | |
Natural Gas Liquid Swaps | | | | Volume | | Price | |
| | (BBls) | | ($/Gallon) | |
September 2006 - March 2008 | | | 12,721 | | | | $ | 1.13 | | |
| | | | | | | | | | | | |
In February 2006 our board of directors has approved the construction of a 25 million cubic feet per day natural gas processing facility along our existing Matli gas gathering system. This facility will process the existing gas supply on our Matli system and will provide additional plant processing capacity for increased system volumes. The expansion project, which is targeted for completion in the 3rd quarter of 2006, is expected to cost approximately $2.8 million, which we also expect to fund using our existing bank credit facility.
On February 1, 2006, we entered into a 5-year definitive purchase agreement with one of our current producers at our Badlands gas gathering system to build additional compression facilities and to expand our existing gas gathering system into South Dakota. The gathering project, which is targeted for completion in the 2nd quarter of 2006, is expected to cost approximately $3.0 million, which we expect to fund using our existing bank credit facility.
On January 24, 2006, we announced a regular cash distribution of $0.625 per unit for the fourth quarter of 2005. The distribution to all common, subordinated and general partner units was payable on February 14, 2006 to all unitholders of record on February 4, 2006. The aggregate amount of the distribution was $5.6 million. As provided for in our Partnership Agreement, our general partner is entitled to receive increasing percentages, up to a maximum of 50% of the cash distributed in excess of $0.495 in any quarter as “incentive distributions.” This distribution of $0.625 per unit exceeds the $0.495 per unit by $0.13. Accordingly, our general partner received an additional $249.
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