Hiland Partners, LP - 10-K Annual Report

Amount

Asset Retirement Obligation, January 1, 2003

Plus: Asset Retirement Obligation accretion expense

Asset Retirement Obligation, December 31, 2003

Plus: Asset Retirement Obligation accretion expense

Asset Retirement Obligation, December 31, 2004

Items 1. and 2. Business and Properties

Our Formation and Initial Public Offering

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 development 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 October 22, 2004, we filed a registration statement on Form S-1 with the United States Securities and Exchange Commission (the “SEC”) relating to a proposed underwritten initial public offering of limited partnership units in Hiland Partners, LP. On February 9, 2005, the SEC declared our registration statement on Form S-1 effective and we priced 2,000,000 common units for the initial public offering at a price of $22.50 per unit. On February 10, 2005, our common units began trading on the Nasdaq National Market under the symbol “HLND.” 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. The proceeds of the public offering were used to: (i) repay approximately $22.9 million of outstanding indebtedness, (ii) pay the remaining $1.8 million of expenses associated with the offering and the related formation transactions, (iii) make a distribution of approximately $3.5 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, (iv) replenish approximately $13.6 million of working capital and (vi) redeem an aggregate of 300,000 common units from an affiliate of Harold Hamm and the Hamm Trusts for $6.3 million.

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, 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 services segment, we provide compressed air and water to Continental Resources, Inc. Continental Resources, Inc. 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 seven natural gas gathering systems with approximately 825 miles of gas gathering pipelines, four natural gas processing plants, three natural gas treating facilities and two 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, Inc., 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, Inc. has active exploration and production assets and through acquisitions of existing systems which we have then expanded. Since inception, we have constructed 280 miles of natural gas gathering pipelines, three natural gas processing plants, two treating facilities and one fractionation facility. In addition, we have acquired 545 miles of natural gas gathering pipelines, one natural gas processing plant, one treating facility and one fractionation facility. Our pro forma total segment margin for the year ended December 31, 2004 was $25.1 million. Please see “Item 6. Selected Historical and Pro Forma Financial and Operating Data” for a reconciliation of our pro forma total segment margin to operating income (loss), which is the most comparable GAAP financial measure.

Midstream Segment

Our midstream assets include 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 525-mile gas gathering system located in northwest Oklahoma that gathers, compresses, dehydrates and processes natural gas. Our Eagle Chief gathering system has a capacity of 30,000 Mcf/d and the average volume of natural gas flowing through the system, or throughput, was approximately 20,250 Mcf/d for the year ended December 31, 2004. The system represented approximately 33.3% of our pro forma total segment margin for the year ended December 31, 2004.

· 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. Our Worland gathering system has a capacity of 8,000 Mcf/d and average throughput was approximately 4,050 Mcf/d for the year ended December 31, 2004. The system represented approximately 22.0% of our pro forma total segment margin for the year ended December 31, 2004.

· 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. Our Badlands gathering system has a capacity of 5,000 Mcf/d and average throughput was approximately 3,210 Mcf/d for the year ended December 31, 2004. The system represented approximately 17.8% of our pro forma total segment margin for the year ended December 31, 2004.

· Matli Gathering System. The Matli gathering system is a 23-mile gas gathering system located in central Oklahoma that gathers, compresses, dehydrates, treats and processes natural gas. Our Matli gathering system has a capacity of 20,000 Mcf/d and average throughput was approximately 15,060 Mcf/d for the year ended December 31, 2004. The system represented approximately 9.4% of our pro forma total segment margin for the year ended December 31, 2004.

· Other Systems. We also own three natural gas gathering systems located in Texas, Mississippi and Oklahoma. These systems represented approximately 2.2% of our pro forma total segment margin for the year ended December 31, 2004.

The table set forth below contains certain information regarding our Eagle Chief gathering system, Worland gathering system, Badlands gathering system, Matli gathering system and our other gathering systems as of or for the year ended December 31, 2004.

Asset	Type	Length (Miles)		Approximate Wells Connected		Throughput Capacity (Mcf/d)		Average Throughput (Mcf/d)		Utilization of Capacity (%)
Eagle Chief	Gathering pipelines		525		370		30,000		20,250		68	%
gathering system	Processing plant		—		—		25,000		20,250		81	%
Worland gathering	Gathering pipelines		151		94		8,000		4,050		51	%
system	Processing plant		—		—		8,000		4,050		51	%
	Treating facility		—		—		8,000		4,050		51	%
	Fractionation facility (Bbls/d)		—		—		650		270		42	%
Badlands	Gathering pipelines		108		96		5,000		3,210		64	%
gathering	Processing plant		—		—		5,000		3,210		64	%
system	Treating facility		—		—		7,100		3,210		45	%
	Fractionation facility (Bbls/d)		—		—		600		330		55	%
Matli gathering	Gathering pipelines		23		39		20,000		15,060		75	%
system	Processing plant		—		—		10,000		4,955		50	%
	Treating facility		—		—		10,000		9,875		99	%
Other Systems	Gathering pipelines		18		27		7,000		4,445		64	%
	Total		825		626

Option to Purchase Bakken Gathering System. We also have an exclusive two-year option to purchase the Bakken gathering system from Hiland Partners, LLC, an affiliate of our general partner, at fair market value at the time of purchase. Hiland Partners, LLC is constructing the Bakken gathering system, which we expect to consist of approximately 200 miles of natural gas gathering pipelines, a processing plant, two compressor stations and a fractionation facility. The Bakken gathering system is located in eastern

Montana 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. The Bakken processing plant and a portion of the gathering system became operational on November 8, 2004 and total plant throughput on December 31, 2004 was 4,750 Mcf. For a more detailed discussion of this option agreement, please read “—Option to Purchase Bakken Gathering System.”

Compression Segment

We provide air and water compression services under a four-year, fixed-fee contract 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, Inc. and are ultimately utilized by Continental Resources, Inc. in its oil and gas secondary recovery operations. The natural gas produced by Continental Resources, Inc. flows through our Badlands gathering system. Prior to our initial public offering and our entrance into the service arrangement, we leased this equipment to Continental Resources, Inc. The payments we received under that lease represented approximately 15.3% of our pro forma total segment margin for the year ended December 31, 2004.

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 seven gas gathering systems. A majority of our growth has come from gas gathering systems and plants that we have constructed, including the Eagle Chief, Badlands and Matli gathering systems. Since building the Eagle Chief gathering system, we have expanded that system by constructing 377 miles of gathering pipeline and acquiring approximately 148 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. 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. Additionally, 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. As of March 14, 2005, we do not have any outstanding indebtedness. Our new $55 million bank credit facility contains a $47.5 million revolving facility for acquisitions and capital expenditures and a $7.5 million working capital facility. We have the right to increase our borrowing capacity under the acquisition facility by an additional $35.0 million in connection with any purchase, including the Bakken gathering system. We believe the available capacity under this new 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 almost 25 years of energy industry experience.

Business Strategies

Our management team is committed to increasing the amount of cash available for distribution 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 increased demand for our midstream services. These projects include expansion of existing systems and construction of new facilities.

· 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. For example, our option to purchase the Bakken gathering system provides us with an acquisition opportunity in a new geographic area that has further growth potential.

· 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 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 825 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 525 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 20,250 Mcf/d for the year ended December 31, 2004. 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 148 miles of gathering pipelines.

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, 2004, the facility processed approximately 20,250 Mcf/d of natural gas and produced approximately 665 Bbls/d of NGLs.

Natural Gas Supply. As of December 31, 2004, 370 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 Energy Corporation and Continental Resources, Inc., which represented approximately 61.7% and 14.4%, respectively, of the Eagle Chief gathering system’s natural gas supply for the year ended December 31, 2004.

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 percent-of-proceeds contracts, percent-of-index contracts or fee-based contracts. For the year ended December 31, 2004, approximately 41.5%, 53.2% and 5.3% of our pro forma total segment margin attributable to the Eagle Chief gathering system was derived from percent-of-proceeds, percent-of-index and fee-based contracts, respectively. For a more complete

discussion of our natural gas purchase contracts, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our 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 20,250 Mcf/d for December 2004. In addition, during the year ended December 31, 2004, we added 40 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 ONEOK Gas Transportation, L.L.C. 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 Koch Hydrocarbon, LP’s Medford facility for fractionation. We are currently selling the NGLs to Koch Hydrocarbon, LP under a year to year contract.

Our primary purchasers of residue gas and NGLs on the Eagle Chief gathering system are BP Energy Company, OGE Energy Resources, Inc. and Koch Hydrocarbon, LP, which represented approximately 31.3%, 34.7% and 16.9%, respectively, of the revenues from such sales for the year ended December 31, 2004.

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 4,050 Mcf/d for the year ended December 31, 2004. There are four gas compressor stations located within the gathering system, comprised of six units with an aggregate of approximately 2,200 horsepower.

We acquired the Worland gathering system, including the Worland processing plant, in 2000. This 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 year ended December 31, 2004, the facility processed approximately 4,050 Mcf/d of natural gas and produced approximately 450 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 year ended December 31, 2004, the facility fractionated an average of approximately 270 Bbls/d to produce approximately 85 Bbls/d of propane and approximately 100 Bbls/d of a mixture of butane and gasoline.

Natural Gas Supply. As of December 31, 2004, 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, Inc. and KCS Resources, Inc., which represented approximately 56.5% and 34.9%, respectively, of the Worland gathering system’s natural gas supply for the year ended December 31, 2004.

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 year ended December 31, 2004, approximately 93.8% and 6.2% of our pro forma 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, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our 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 Company 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 are Rainbow Gas Company and a subsidiary of Kinder Morgan Energy Partners, L.P. which represented approximately 61.4% and 22.9%, respectively, of revenues from such sales on the Worland gathering system for the year ended December 31, 2004.

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 3,210 Mcf/d for the year ended December 31, 2004. 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, 2004, the facility processed approximately 3,210 Mcf/d of natural gas and produced approximately 350 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, 2004, the facility fractionated an average of approximately 330 Bbls/d of to produce approximately 80 Bbls/d of propane and approximately 185 Bbls/d of a mixture of butane and gasoline.

Natural Gas Supply. As of December 31, 2004, 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, Inc., Luff Exploration Company and Burlington Resources Trading, Inc., which represented approximately 61.7%, 20.4% and 11.9%, respectively, of the Badlands gathering system’s natural gas supply for the year ended December 31, 2004.

The natural gas supplied to the Badlands 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. For a more complete discussion of our natural gas purchase contracts, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our 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, Inc. under a long-term contract 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.

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 are Continental Resources, Inc., Bear Paw Energy, a subsidiary of Northern Border Partners, L.P. and a subsidiary of Plains All American Pipeline, L.P., which represented approximately 39.5%, 18.6% and 16.1%, respectively, of the revenues from such sales for the year ended December 31, 2004.

Matli Gathering System

General. The Matli Gathering System is located in central Oklahoma and consists of approximately 23 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 15,060 Mcf/d for the year ended December 31, 2004. 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 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, 2004, the facility processed approximately 4,955 Mcf/d of natural gas and produced approximately 115 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, 2004, the facility treated approximately 9,875 Mcf/d of natural gas.

Natural Gas Supply. As of December 31, 2004, 39 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 Range Resources Corporation and Continental Resources, Inc., which represented approximately 47.9% and 42.6%, respectively, of the Matli gathering system’s natural gas supply for the year ended December 31, 2004.

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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our 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 transported by truck to the Koch Hydrocarbon, LP Medford facility for fractionation.

Our primary purchasers of residue gas and NGLs on the Matli gathering system are BP Energy Company and OGE Energy Resources, Inc., which represented approximately 53.1% and 36.1%, respectively, of the revenues from such sales for the year ended December 31, 2004.

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.

· 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.

Option to Purchase Bakken Gathering System

Pursuant to an option agreement contained in an 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 its Bakken gathering system at fair market value at the time of purchase. The Bakken gathering system consisted of approximately 135 miles of gas gathering pipeline as of December 31, 2004 and is located in eastern Montana. Upon completion of construction, we expect the Bakken gathering system to consist of 200 miles of natural gas gathering pipeline, a processing plant, two compressor stations, which are comprised of three units with an aggregate of approximately 4,434 horsepower, and one fractionation facility. The Bakken processing plant and a portion of the gathering system became operational on November 8, 2004 and total plant throughput on December 31, 2004 was 4,750 Mcf. The gathering system has an initial capacity of approximately 20,000 Mcf/d.

Currently, there are several producers actively drilling in the area. Hiland Partners, LLC has entered into long-term natural gas supply contracts with three of the most active drillers in the area under which such producers have dedicated their acreage in the area to Hiland Partners, LLC. Currently, there are approximately 115 wells dedicated to the Bakken gathering system. The current suppliers of natural gas to the gathering system include Lyco Energy Corporation, Continental Resources, Inc. and a subsidiary of Burlington Resources Inc.

In accordance with the option agreement, if we decide to exercise our option, we must provide written notice to Hiland Partners, LLC stating our intention to exercise our option to purchase the Bakken gathering system. Within 30 days after we deliver notice, Hiland Partners, LLC must propose to us, in writing, a fair market value for the Bakken gathering system. The conflicts committee of our general partner will determine, with the assistance of an independent financial advisor, whether the proposed price is fair to our public unitholders. If neither party can agree on the purchase price after good faith negotiations by both parties, we and Hiland Partners, LLC will appoint a mutually agreed upon investment banking firm to determine the fair market value. Once the investment bank submits its valuation, we will have the right, but not the obligation, to purchase the asset at the price determined by the investment bank. In the second half of 2005, when we expect the Bakken gathering system construction to be complete, our management will determine whether to recommend the exercise of our option to acquire the Bakken gathering system to the Board of Directors of our general partner. The exercise of the option will require the approval of the conflicts committee of the Board of Directors of our general partner.

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 three units with an aggregate of approximately 900 horsepower. 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. 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, Inc. and are ultimately utilized by Continental Resources, Inc. in its oil and gas secondary recovery operations. For a description of our compression services agreement with Continental Resources, Inc., please read “Item 7. 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 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.

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 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 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 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 all material environmental and safety laws and regulations that relate to the midstream natural gas industry. We believe that we are in substantial compliance with all of these environmental laws and regulations.

PART II

Item 5. Market for Registrant’s Common Units and Related Stockholder Matters

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.

As of March 28, 2005, we had approximately 3,500 common unitholders, including beneficial owners of common units held in street name.

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.”

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 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.

Our Formation and Initial Public Offering

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. On October 21, 2004, in connection with the formation of Hiland Partners, LP, the partnership issued to (i) Hiland Partners GP, LLC the 2% general partner interest in Hiland Partners, LP for $20 and (ii) Continental Gas, Inc. the 98% limited partner interest in Hiland Partners, LP for $980. The issuance was exempt from registration under Section 4(2) of the Securities Act.

On February 15, 2005, 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 Hiland Partners, LP 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, in exchange for an aggregate of 720,000 common units and 4,080,000 subordinated units in Hiland Partners, LP, the continuation of the 2% general partner interest in Hiland Partners, LP and all of the incentive distribution rights in Hiland Partners, LP, which entitle the general partner to increasing percentages of the cash we distribute in excess of $0.495 per unit per quarter. These issuances were exempt from registration under Section 4(2) of the Securities Act.

On October 22, 2004, we filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten initial public offering of limited partnership units in Hiland Partners, LP. On February 9, 2005, the SEC declared our registration statement on Form S-1 effective and we priced 2,000,000 common units for the initial public offering at a price of $22.50 per unit. On February 10, 2005, our common units began trading on the Nasdaq National Market under the symbol “HLND.” 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. The managing underwriters for the offering were A.G. Edwards, Raymond James and RBC Capital Markets. Total proceeds from the sale of the units were $48.1 million, net of $3.6 million of underwriting commissions. The proceeds of the public offering were used to: (i) repay approximately $22.9 million of outstanding indebtedness, (ii) pay the remaining $1.8 million of expenses associated with the offering and the related formation transactions, (iii) make a distribution of approximately $3.5 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, (iv) replenish approximately $13.6 million of working capital and (vi) redeem an aggregate of 300,000 common units from an affiliate of Harold Hamm and the Hamm Trusts for $6.3 million.

Item 6. Selected Historical and Pro Forma Financial and Operating Data

The following table shows selected historical financial and operating data of Continental Gas, Inc. and pro forma financial data of Hiland Partners, LP for the periods and as of the dates indicated. The selected historical financial data for the years ended December 31, 2001, 2002, 2003 and 2004 are derived from the audited financial statements of Continental Gas, Inc. The selected historical financial data for the year ended December 31, 2000 are derived from the unaudited financial statements of Continental Gas, Inc. The selected pro forma financial data as of December 31, 2004 and for the year ended December 31, 2004 are derived from the unaudited pro forma financial statements of Hiland Partners, LP. The unaudited pro forma balance sheet data gives pro forma effect to the following transactions as if they had occurred on December 31, 2004 and the unaudited pro forma statement of operations data gives pro forma effect to the following transactions as if they had occurred on January 1, 2004:

· the formation of and transfer of assets to Hiland Partners, LP; and

· our initial public offering and the application of the proceeds thereof.

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 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.

We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma combined financial statements and the accompanying notes included in “Item 8. Financial Statements and Supplementary Data.” The table should be read together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

																	Hiland
																	Partners, LP
																	Pro Forma
	Predecessor																Year
	Continental Gas, Inc.																Ended
	Year Ended December 31,																December 31,
	2000				2001			2002			2003			2004			2004
	(unaudited)				(audited)												(unaudited)
	(in thousands, except per unit and operating data)
Summary of Operations Data:
Total revenues		$	35,977		$	45,489		$	35,228		$	76,018		$	98,296			$	110,733
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		28,844			33,929			27,935			67,002			82,532				85,584
Operations and maintenance expenses		2,681			3,002			3,509			3,714			4,933				6,817
Depreciation, amortization and accretion		1,986			2,072			2,370			3,304			4,127				9,021
Property impairment expense		—			—			—			1,535			—				—
(Gain) loss on asset sales		(522		)	(76		)	(12		)	34			(19		)		(19		)
Bad debt expense		—			—			295			—			—				—
General and administrative expenses		613			688			730			770			1,082				1,179
Total operating costs and expenses		33,602			39,615			34,827			76,359			92,655				102,582
Operating income (loss)		2,375			5,874			401			(341		)	5,641				8,151
Other income (expense):
Interest expense		(573		)	(350		)	(185		)	(473		)	(702		)		—
Amortization of deferred loan costs		—			—			—			(24		)	(102		)		(386		)
Interest income and other		49			95			72			10			40				41
Total other income (expense)		(524		)	(255		)	(113		)	(487		)	(764		)		(345		)
Income (loss) from continuing operations		1,851			5,619			288			(828		)	4,877				7,806
Discontinued operations, net		633			285			199			246			35				—
Income (loss) before change in accounting principle		2,484			5,904			487			(582		)	4,912				7,806
Cumulative effect of change in accounting principle		—			—			—			1,554			—				—
Net income		$	2,484		$	5,904		$	487		$	972		$	4,912			$	7,806
Pro forma net income per limited partner unit(1)																		$	1.13
Balance Sheet Data (at period end):
Property and equipment, at cost, net		$	19,462		$	20,638		$	23,722		$	38,425		$	37,075			$	68,675
Total assets		25,302			25,435			28,058			47,840			49,175				109,613
Accounts payable—affiliates		1,103			877			2,150			2,814			2,998				3,097
Long-term debt, net of current maturities		5,839			2,975			3,491			14,571			12,643				—
Net equity		14,376			20,280			20,767			21,739			24,510				98,898
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities		$	2,182		$	6,432		$	4,809		$	4,464		$	7,957
Investing activities		1,322			(3,242		)	(5,645		)	(17,286		)	(5,290		)
Financing activities		(3,661		)	(2,865		)	516			13,212			(2,946		)
Other Financial Data:
Midstream segment margin		$	7,133		$	11,560		$	7,293		$	9,016		$	15,764			$	21,295
Compression segment margin		—			—			—			—			—				3,854
Total segment margin		$	7,133		$	11,560		$	7,293		$	9,016		$	15,764			$	25,149
EBITDA		$	5,043		$	8,326		$	3,042		$	4,773	(2)	$	9,843			$	17,213
Maintenance capital expenditures		$	268		$	844		$	1,826		$	1,769		$	1,693
Expansion capital expenditures		1,050			2,339			3,244			14,900			3,474
Discontinued operations		4			235			690			745			159
Total capital expenditures		$	1,322		$	3,418		$	5,760		$	17,414		$	5,326
Operating Data:
Natural gas sales (MMBtu/d)					24,117			26,599			37,701			40,560				43,541
NGL sales (Bbls/d)					881			950			895			1,133				1,375

(1) Net income (loss) per unit is not applicable for periods prior to our initial public offering. Pro forma net income per limited partner unit for the year ended December 31, 2004 of $1.13 is presented pro forma for our initial public offering.

(2) 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.

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 and pro forma basis for each of the periods indicated.

																			Hiland
																			Partners, LP
																			Pro Forma
	Predecessor																		Year
	Continental Gas, Inc.																		Ended
	Year Ended December 31,																		December 31,
	2000				2001				2002				2003			2004			2004
	(unaudited)				(audited)														(unaudited)
	(in thousands, except per unit and operating data)
Reconciliation of EBITDA to Net Income:
Net income		$	2,484			$	5,904			$	487		$	972		$	4,912			$	7,806
Add:
Depreciation, amortization and accretion		1,986				2,072				2,370			3,304			4,127				9,021
Amortization of deferred loan costs		—				—				—			24			102				386
Interest Expense		573				350				185			473			702				—
EBITDA		$	5,043			$	8,326			$	3,042		$	4,773	(1)	$	9,843			$	17,213
Reconciliation of Total Segment Margin to Operating Income (Loss):
Operating income (loss)		$	2,375			$	5,874			$	401		$	(341	)	$	5,641			$	8,151
Add:
Operations and maintenance expenses		2,681				3,002				3,509			3,714			4,933				6,817
Depreciation, amortization and accretion		1,986				2,072				2,370			3,304			4,127				9,021
Property impairment expense		—				—				—			1,535			—				—
(Gain) loss on asset sales		(522		)		(76		)		(12		)	34			(19		)		(19		)
Bad debt expense		—				—				295			—			—				—
General and administrative expenses		613				688				730			770			1,082				1,179
Total segment margin		$	7,133			$	11,560			$	7,293		$	9,016		$	15,764			$	25,149

(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 Financial Statements and notes thereto included elsewhere in this annual report on Form 10-K.

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.

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 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.

Continental Gas, Inc. historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland gathering system. Hiland Partners, LLC historically has owned our Worland gathering system, our compression services assets and the Bakken gathering system.

On October 22, 2004, we filed a registration statement on Form S-1 with the SEC relating to a proposed underwritten public offering of limited partnership units in Hiland Partners, LP. On February 9, 2005, the SEC declared our registration statement on Form S-1 effective and we priced 2,000,000 common units for the initial public offering at a price of $22.50 per unit. On February 10, 2005, our common units began trading on the Nasdaq National Market under the symbol “HLND.” 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. The proceeds of the public offering were used to: (i) repay approximately $22.9 million of outstanding indebtedness, (ii) pay the remaining $1.8 million of expenses associated with the offering and the related formation transactions, (iii) make a distribution of approximately $3.5 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, (iv) replenish approximately $13.6 million of working capital and (vi) redeem an aggregate of 300,000 common units from an affiliate of Harold Hamm and the Hamm Trusts for $6.3 million.

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, 2004, this segment generated approximately 84.7% of our total segment margin on a pro forma basis after giving effect to the formation transactions.

· 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, 2004, this segment generated approximately 15.3% of our total segment margin on a pro forma basis after giving effect to the formation transactions.

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.

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 as described in “—Items Impacting Comparability of Our Financial Results,” our compression segment margin will equal the fee we will earn under our Compression Services Agreement with Continental Resources, Inc. for providing air compression and water injection services. The fee that we will earn under this agreement will be fixed so long as our facilities meet specified availability requirements, regardless of Continental Resources, Inc.’s utilization. As a result, our compression segment margin will be 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.

In 2003, our general and administrative expenses were approximately $0.9 million, and for 2004 these expenses were approximately $1.2 million. We believe that our general and administrative expenses will increase as a result of our becoming a public company. We currently anticipate that our total annual general and administrative expenses following completion of this offering will be approximately $2.3 million, or $0.6 million per quarter. This increase is 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. Continental Resources, Inc. currently provides 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.

In the omnibus agreement, Continental Resources, Inc. agreed to continue to provide these services to us for two years after our initial public offering, at the lower of Continental Resources, Inc.’s cost to provide the services or $50,000 per year.

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 facilities. 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. 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 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 contracts to sell approximately 50,000 MMBtu of natural gas per month through December 2007 with weighted average fixed prices per MMBtu of $4.53, $4.47 and $4.49, respectively, for years 2005 through 2007. We refer to these types of contracts as forward sales contracts.

Our NGL Sales Arrangements

We sell NGLs and NGL products at the tailgate of our facilities to Koch 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.

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:

· Percent-of-proceeds arrangements. Under percent-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, 2004, we purchased 32.9% 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 increase as the price of NGLs increase relative to the price of natural gas, and our total segment margin under these arrangements decrease as the price of natural gas increases relative to the price of NGLs. For the year ended December 31, 2004, we purchased 31.2% of our total volumes under these types of fee arrangement.

· 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, 2004, we purchased 35.9% of our total volumes under these types of fee arrangements.

The following is a summary of our four largest natural gas purchase contracts. Under each of the contracts, we are required to purchase the supplied gas, subject to the demands of our resale purchasers and the operating conditions and capacity of our facilities. We do not guarantee the purchase of any particular quantity of the gas which is available for sale. The supplier delivers the gas to us at the inlet of our gathering systems and we obtain title to the gas at the delivery point. The gas delivered to us is required to meet specified quality requirements.

Continental Resources, Inc. 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, 2004, gas purchased under the contract represented approximately 12.9% of our aggregate natural gas supply for that period. 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 19 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.

Chesapeake Energy Corporation. We are a party to a percentage-of-proceeds gas purchase contract with Chesapeake Energy Corporation dated as of January 1, 2004. For the year ended December 31, 2004, gas purchased under the contract represented approximately 8.0% of our aggregate natural gas supply for

that period. Under the contract, Chesapeake Energy Corporation has committed to supply us with all of the gas it produces in a designated area primarily in Woods County, Oklahoma. The contract currently covers approximately 17 wells that are connected to our Eagle Chief gathering system. We pay Chesapeake Energy Corporation the following: (1) a fixed percentage of the applicable index price for the volumes of each NGL product derived at our Eagle Chief processing plant from the raw natural gas produced from the dedicated wells less a deduction for delivery, transportation and fractionation costs and (2) a fixed percentage of the applicable index price for the residue natural gas derived from the raw natural gas produced from the dedicated wells. The contract remains in effect for the life of the gas leases contained in the dedicated area. However, either party has the right to terminate the contract on January 1, 2009 or on any subsequent anniversary by giving 30 days’ notice.

We are also a party to a percentage-of-index gas purchase contract with Chesapeake Energy Corporation dated July 20, 1983. For the year ended December 31, 2004, gas purchased under the contract represented approximately 10.9% of our aggregate natural gas supply for that period. Under the contract, Chesapeake Energy Corporation has committed to supply us with all of the gas it produces in a designated area in Woods County, Oklahoma. The contract currently covers approximately 10 wells that are connected to our Eagle Chief gathering system. Under this contract, we pay Chesapeake Energy Corporation a price for the gas equal to a fixed percentage of the applicable index price. This contract may be terminated by either party on each anniversary of the date of the contract with 30 days’ notice.

Range Resources Corporation. We are a party to a fixed-fee gas purchase contract with Range Resources Corporation dated as of November 1, 2002. For the year ended December 31, 2004, gas purchased under the contract represented approximately 10.5% of our aggregate natural gas supply for that period. Under the contract, Range Resources Corporation 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 17 wells that are connected to our Matli gathering system. Under this contract, we pay Range Resources Corporation the applicable index price for the raw natural gas delivered to us less a fixed transportation fee. This contract remains in effective for the life of the lease. However, either party has the right to terminate the contract on November 1, 2007 or on any subsequent anniversary by giving 30 days’ notice. In addition, 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. 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. For example, we have the option to purchase the Bakken gathering system which is located in Montana. 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 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.

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.

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 gathering system. As a result, our historical financial statements are the financial statements of Continental Gas, Inc. For a discussion of the results of operations of Continental Gas, Inc., please read “—Continental Gas, Inc.

Results of Operations.” The financial statements of Continental Gas, Inc., together with the notes thereto, are also included in this annual report on Form 10-K.

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. For a discussion of the results of operations of Hiland Partners, LLC, please read “—Hiland Partners, LLC Results of Operations.” The financial statements of Hiland Partners, LLC, together with the notes thereto, are included in this annual report on Form 10-K.

Restructuring of Compression Facilities Lease

Prior to consummation of our formation, 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 will receive a fixed payment of approximately $4.8 million per year as compared to $3.8 million under the prior lease agreement. In connection with the new services arrangement, we will 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. 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.

Our Pro Forma Results of Operations

Set forth in the table below is pro forma financial and operating data for our compression and midstream segments for the periods indicated.

	Hiland Partners, LP Pro Forma
	Year Ended December 31, 2004
	(unaudited)
	(in thousands)
Total Segment Margin Data:
Midstream revenues		$	106,879
Midstream purchases		85,584
Midstream segment margin		21,295
Compression revenues(1)		3,854
Total segment margin		$	25,149
Summary of Operations Data:
Midstream revenues		$	106,879
Compression revenues		3,854
Total revenues		110,733
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		85,584
Operations and maintenance expenses		6,817
Depreciation and amortization expenses		9,021
Gain on asset sales		(19		)
General and administrative expenses		1,179
Total operating costs and expenses		102,582
Operating income		8,151
Other income (expense):
Interest income and other		41
Amortization of deferred loan costs		(386		)
Interest expense		—
Total other income (expense)		(345		)
Net income		$	7,806
Operating Data (unaudited):
Natural gas sales (MMBtu/d)		43,541
NGL sales (Bbls/d)		1,375

(1) Compression revenues and compression segment margin are the same. There are no compression purchases associated with the compression segment.

Continental Gas, Inc. Results of Operations

The following table and the discussion that follows provide a comparison of the results of operations of Continental Gas, Inc., our accounting predecessor, for the years ended December 31, 2002, 2003 and 2004.

	Predecessor
	Continental Gas, Inc.
	2002			2003(1)			2004
	(audited)
	(in thousands)
Midstream Segment Margin Data:
Midstream revenues	$	35,228		$	76,018		$	98,296
Midstream purchases	27,935			67,002			82,532
Midstream segment margin	$	7,293		$	9,016		$	15,764
Summary of Operations Data:
Midstream revenues	$	35,228		$	76,018		$	98,296
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	27,935			67,002			82,532
Operations and maintenance expenses	3,509			3,714			4,933
Property impairment expense	—			1,535			—
Depreciation and amortization expenses	2,370			3,304			4,127
(Gain) loss on asset sales	(12		)	34			(19		)
Bad debt expense	295			—			—
General and administrative expenses	730			770			1,082
Total operating costs and expenses	34,827			76,359			92,655
Operating income (loss)	401			(341		)	5,641
Interest and other financing costs, net	113			487			764
Income (loss) from continuing operations	288			(828		)	4,877
Discontinued operations, net	199			246			35
Income (loss) before change in accounting principle	487			(582		)	4,912
Cumulative effect of change in accounting principle	—			1,554			—
Net income	$	487		$	972		$	4,912
Operating Data (unaudited):
Natural gas sales (MMBtu/d)	26,599			37,701			40,560
NGL sales (Bbls/d)	950			895			1,133

(1) Includes operations of our Carmen gathering system beginning August 1, 2003, the date we acquired these assets.

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 Expenses. 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 Expense. 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 and Amortization. Depreciation and amortization 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 24.2%. 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.

Interest and Other Financing Costs, Net. Interest and other financing costs 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.

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.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Revenues. Midstream revenues were $76.0 million for the year ended December 31, 2003 compared to $35.2 million for the year ended December 31, 2002, an increase of $40.8 million, or 115.8%. Of this increase, $27.8 million is attributable to higher average realized natural gas sales prices and averaged realized NGL sales prices and $11.8 million is attributable to an increase in residue sales volumes offset partially by a decrease in NGL sales volumes.

Natural gas sales volumes were 37,701 MMBtu/d for the year ended December 31, 2003 compared to 26,599 MMBtu/d for the year ended December 31, 2002, an increase of 11,102 MMBtu/d, or 41.7%. NGL sales volumes were 895 Bbls/d for the year ended December 31, 2003 compared to 950 Bbls/d for the year ended December 31, 2002, a decrease of 55 Bbls/d, or 5.8%. Natural gas sales volumes increased primarily as a result of our acquisition of the Carmen gathering system.

Average realized natural gas sales prices were $4.84 per MMBtu for the year ended December 31, 2003 compared to $2.99 per MMBtu for the year ended December 31, 2002, an increase of $1.85 per MMBtu, or 61.9%. In addition, average realized NGL sales prices were $0.58 per gallon for the year ended December 31, 2003 compared to $0.41 per gallon for the year ended December 31, 2002, an increase of $0.17 per gallon, or 41.5%. 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, 2003 compared to the year ended December 31, 2002.

Midstream Purchases. Midstream purchases were $67.0 million for the year ended December 31, 2003 compared to $27.9 million for the year ended December 31, 2002, an increase of $39.1 million, or 139.8%. 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 and an increase in natural gas and NGL prices.

Property Impairment Expense. 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 2002.

Depreciation and Amortization. Depreciation and amortization totaled $3.3 million for the year ended December 31, 2003 compared with $2.4 million for the year ended December 31, 2002, an increase of $0.9 million, or 39.4%. The increase was primarily due to our acquisition of the Carmen gathering system in August 2003 and expansion of the Matli gathering system.

Interest and Other Financing Costs, Net. Interest and other financing costs totaled $0.49 million for the year ended December 31, 2003 compared with $0.11 million for the year ended December 31, 2002, an increase of $0.37 million, or 331.0%. This increase relates to the acquisition of the Carmen gathering system in August 2003 and expansion of the Matli gathering system.

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. This cumulative effect of change in accounting principle was the result of our January 1, 2003 adoption of SFAS No. 143.

Hiland Partners, LLC Results of Operations

The following table and the discussion that follows provide a comparison of the results of operations of Hiland Partners, LLC for the years ended December 31, 2002, 2003 and 2004.

	Hiland Partners, LLC
	Year Ended December 31,
	2002		2003			2004
	(audited)
	(in thousands)
Total Segment Margin Data:
Midstream revenues	$	5,480	$	7,262		$	10,481
Midstream purchases	1,439		2,826			4,600
Midstream segment margin	4,041		4,436			5,881
Compression revenues(1)	244		3,300			3,854
Total segment margin(2)	$	4,285	$	7,736		$	9,735
Summary of Operations Data:
Midstream revenues	$	5,480	$	7,262		$	10,481
Compression revenues	244		3,300			3,854
Total revenues	5,724		10,562			14,335
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)	1,439		2,826			4,600
Operations and maintenance expenses	1,779		1,900			2,080
Depreciation and amortization expenses	522		1,684			2,311
Loss on asset sales	36		—			—
General and administrative expenses	156		101			97
Total operating costs and expenses	3,932		6,511			9,088
Operating income	1,792		4,051			5,247
Interest and other financing costs, net	278		563			766
Income before change in accounting principle	1,514		3,488			4,481
Cumulative effect of change in accounting principle	—		(73		)	—
Net income	$	1,514	$	3,415		$	4,481
Operating Data (unaudited):
Natural gas sales (MMBtu/d)	4,549		3,756			3,503
NGL sales (Bbls/d)	282		282			304

(1) Compression revenues and compression segment margin are the same. There are no compression purchases associated with the compression segment.

(2) Reconciliation of total segment margin to operating income:

	Hiland Partners, LLC
	Year Ended December 31,
	2002		2003		2004
	(audited)
	(in thousands)
Operating income	$	1,792	$	4,051	$	5,247
Add:
Operations and maintenance expenses	1,779		1,900		2,080
Depreciation and amortization expenses	522		1,684		2,311
(Gain) loss on asset sales	36		—		—
General and administrative expenses	156		101		97
Total segment margin	$	4,285	$	7,736	$	9,735

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Revenues. Total revenues (midstream and compression) were $14.3 million for the year ended December 31, 2004 compared to $10.6 million for the year ended December 31, 2003, an increase of $3.8 million, or 35.7%.

Midstream revenues were $10.5 million for the year ended December 31, 2004 compared to $7.3 million for the year ended December 31, 2003, an increase of $3.2 million, or 44.3%. Of this increase, $2.9 million was attributable to higher average realized natural gas sales prices and average realized NGL sales prices. This increase was offset by a $0.1 million decrease due to lower residue sales volumes.

Natural gas sales volumes were 3,503 MMBtu/d for the year ended December 31, 2004 compared to 3,756 MMBtu/d for the year ended December 31, 2003, a decrease of 253 MMBtu/d, or 6.7%. NGL sales volumes were 304 Bbls/d for the year ended December 31, 2004 compared to 282 Bbls/d for the year ended December 31, 2003, an increase of 22 Bbls/d, or 7.8%. Natural gas sales volumes decreased primarily due to the shutdown and maintenance of a high-pressure gas trunk line serving the plant. This line was shut down for a forty-five day period in the first six months of 2004. This decrease was partially offset by volumes associated with the start-up of the Bakken plant. The increase in NGL sales volumes was primarily attributable to NGL extraction volumes associated with the start-up of the Bakken plant.

Average realized natural gas sales prices were $5.32 per MMBtu for the year ended December 31, 2004 compared to $3.39 per MMBtu for the year ended December 31, 2003, an increase of $1.93 per MMBtu, or 56.9%. In addition, average realized NGL sales prices were $0.70 per gallon for the year ended December 31, 2004 compared to $0.60 per gallon for the year ended December 31, 2003, an increase of $0.10 per gallon, or 16.7%. 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.

Compression revenues were $3.9 million for the year ended December 31, 2004 compared to $3.3 million for the year ended December 31, 2003, an increase of $0.6 million, or 16.8%. This increase was directly attributable to the expansion of our compression facilities with a corresponding increase in the monthly lease payment.

Midstream Purchases. Midstream purchases were $4.6 million for the year ended December 31, 2004 compared to $2.8 million for the year ended December 31, 2003, an increase of $1.8 million, or 62.8%. This increase was primarily attributable to purchases associated with the start-up of the Bakken plant and the increase of natural gas and NGL prices.

Depreciation and Amortization. Depreciation and amortization totaled $2.3 million for the year ended December 31, 2004 compared with $1.7 million for the year ended December 31, 2003, an increase of $0.6 million, or 37.2%. The increase was attributable to acquiring additional compression equipment in the second half of 2003 that we leased to Continental Resources and depreciation associated with the Bakken gathering system that became operational on November 8, 2004.

Interest and Other Financing Costs, Net. Interest and other financing costs totaled $0.77 million for the year ended December 31, 2004 compared with $0.56 million for the year ended December 31, 2003, an increase of $0.21 million, or 36.1%. The increase is attributable to financing compression equipment purchased during 2003 and financing the Bakken gathering system which became operational on November 8, 2004.

Cumulative Effect of Change in Accounting Principle. Cumulative effect of change in accounting principle totaled $0.07 million for the year ended December 31, 2003. This cumulative effect of change in accounting principle was the result of our January 1, 2003 adoption of SFAS No. 143.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Revenues. Total revenues (Midstream & Compression) were $10.6 million for the year ended December 31, 2003 compared to $5.7 million for the year ended December 31, 2002, an increase of $4.8 million, or 84.5%.

Midstream revenues were $7.3 million for the year ended December 31, 2003 compared to $5.5 million for the year ended December 31, 2002, an increase of $1.8 million, or 32.5%. Of this increase, $2.6 million was attributable to higher average realized natural gas sales prices and average realized NGL sales prices. This increase was offset by a $0.5 million decrease attributable to lower residue and NGL sales volumes.

Natural gas sales volumes were 3,756 MMBtu/d for the year ended December 31, 2003 compared to 4,549 MMBtu/d for the year ended December 31, 2002, a decrease of 793 MMBtu/d, or 17.4%. The decrease was primarily attributable to the sale of our Dobie Creek pipeline system. NGL sales volumes were relatively stable at 282 Bbls/d for the year ended December 31, 2003 compared to 282 Bbls/d for the year ended December 31, 2002.

Average realized natural gas sales prices were $3.40 per MMBtu for the year ended December 31, 2003 compared to $1.92 per MMBtu for the year ended December 31, 2002, an increase of $1.48 per MMBtu, or 77.1%. In addition, average realized NGL sales prices were $0.60 per gallon for the year ended December 31, 2003 compared to $0.46 per gallon for the year ended December 31, 2002, an increase of $0.14 per gallon or 30.4%. 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, 2003 compared to the year ended December 31, 2002.

Compression revenues were $3.3 million for the year ended December 31, 2003 compared to $0.2 million for the year ended December 31, 2002, an increase of $3.1 million. This increase was directly attributable to the expansion of our compression facilities with a corresponding increase in the monthly lease payment.

Midstream Purchases. Midstream purchases were $2.8 million for the year ended December 31, 2003 compared to $1.4 million for the year ended December 31, 2002, an increase of $1.4 million, or 96.4%. This increase was attributable to the increase of natural gas and NGL prices, partially offset by a decrease in volumes.

Depreciation and Amortization. Depreciation and amortization totaled $1.7 million for the year ended December 31, 2003 compared with $0.5 million for the year ended December 31, 2002, an increase of $1.2 million, or 222.6%. The increase was attributable to adding compression equipment in December 2002 that we lease to Continental Resources.

Interest and Other Financing Costs, Net. Interest and other financing costs totaled $0.56 million for the year ended December 31, 2003 compared with $0.28 million for the year ended December 31, 2002, an increase of $0.29 million, or 102.5%. In December 2002 and in 2003, we purchased compressors that we leased to Continental Resources to be used in their secondary production recovery project. These equipment purchases were made with bank financing.

Cumulative Effect of Change in Accounting Principle. Cumulative effect of change in accounting principle totaled $0.1 million for year ended December 31, 2003. This cumulative effect of change in accounting principle was the result of our January 1, 2003 adoption of SFAS No. 143.

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 “Cautionary Statement about 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. For example, our average throughput increased from 43,900 Mmbtu/d for the first quarter of 2004 to 47,500 Mmbtu/d for the fourth quarter of 2004. 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 2003 and 2004, we generally have seen our margins increase as natural gas prices and NGL prices have increased, primarily as a result of our percent-of-proceeds contracts. During this time, this positive impact on our margins has 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. The credit markets recently have experienced 50-year record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. 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 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

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 will depend 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

Continental Gas, Inc.

Cash flows from operations. 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.

Net cash provided by operating activities was $4.5 million and $4.8 million for the year ended December 31, 2003 and 2002, respectively, a decrease of $0.3 million. Total segment margin increased $1.7 million for the year ended December 31, 2003 as compared to the year ended December 31, 2002. The increase in total segment margin was attributable to an increase of natural gas and NGL prices as well as an increase in natural gas sales volumes. However this increase was offset by changes in working capital items that impacted cash provided by operating activities. Changes in these working capital items provided $2.1 million in 2002 as compared to $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. Net cash used in investing activities was $17.3 million and $5.6 million for the years ended December 31, 2003 and 2002, respectively. 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.

· $5.1 million in 2002 (net of discontinued operations), which includes $1.8 million of capital expenditures for building new gathering facilities in Mississippi and $3.3 million of capital expenditures for continued expansion of our existing gathering systems.

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.

Hiland Partners, LLC

Cash flows from operations. Net cash provided by operating activities was $7.0 million and $5.4 million for 2004 and 2003, respectively, an increase of $1.7 million. Total segment margin increased by $2.0 million and the increase was attributable to increases in our total segment margin as a result of an increase in natural gas and NGL prices and our compression margin as a result of expansion of our compression facilities in the second half of 2003.

Net cash provided by operating activities was $5.4 million and $3.0 million for the year ended December 31, 2003 and 2002, respectively, an increase of $2.4 million. Total segment margin increased $3.5 million for the year ended December 31, 2003 as compared to the year ended December 31, 2002. The increase in total segment margin is primarily attributable to the start-up of our compression segment. Our compression equipment was acquired in December 2002.

Cash flows used in investing activities. Net cash used in investing activities was $24.8 million for 2004 and $5.1 million for 2003. The net cash used in investing activities for 2004 includes $24.4 million related to construction of the Bakken gathering system (which was not contributed to our partnership in connection with our initial public offering). Net cash used in investing activities was $5.1 million and $12.1 million and for the years ended December 31, 2003 and 2002, respectively. Capital expenditures for additions to property, plant and equipment and additions to assets for lease were:

· $5.1 million in 2003, which includes $4.5 million for compressors purchased and leased to Continental Resources, Inc. to be used in their secondary recovery project and $0.6 million for other assets.

· $12.5 million in 2002, which includes $12.0 million for compressors purchased and leased to Continental Resources, Inc. to be used in their secondary recovery project.

Cash flows used in financing activities. Net cash provided by financing activities was $18.0 million for 2004 which was attributable to our net borrowings to finance the construction of the Bakken gathering system. Net cash used in financing activities was $0.3 million for 2003 which was attributable to our repayment of long-term debt. Net cash provided by financing activities was $9.6 million for the year ended December 31, 2002, which was used to acquire compressors that are leased to Continental Resources, Inc. for use in their secondary recovery project.

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 have budgeted $2.0 million for maintenance capital expenditures for the year ending December 31, 2005. During 2004, our capital expenditures, including maintenance and growth capital expenditures, totaled $30.1 million (including $24.4 million for construction of the Bakken gathering system which was not part of our partnership at the time of the offering). We expect to fund future capital expenditures with funds generated from our operations, borrowings under our new credit facility and the issuance of additional equity as appropriate given market conditions.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2004, is as follows:

	Payment Due by Period
Type of Obligation	Total Obligation			Remainder Due in 2005			Due in 2006			Due in 2007-2008			Thereafter
	(in thousands)
Continental Gas, Inc. long-term debt(1)		$	15,072		$	2,429		$	12,643		$	—		$	—
Continental Gas, Inc. operating leases		437			86			92			185			74
Hiland Partners, LLC long-term debt(1)(2)		32,635			9,356			23,279			—			—
Total contractual cash obligations		$	48,144		$	11,871		$	36,014		$	185		$	74

(1) These obligations, other than the obligations related to the Bakken gathering system as described in footnote (2), were retired with proceeds from the initial public offering.

(2) Hiland Partners, LLC’s long-term debt at December 31, 2004 includes $23.3 million that is attributable to the construction of the Bakken gathering system. Neither this $23.3 million of indebtedness nor the Bakken gathering system was conveyed to us in connection with our formation.

In addition to the contractual obligations noted in the table above, Continental Gas has executed fixed price physical forward sales contracts on approximately 50,000 MMBtu per month of natural gas through December 2007 with weighted average fixed prices per MMBtu of $4.53, $4.47 and $4.49, respectively, for years 2005 through 2007. 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 off-balance sheet arrangements as of December 31, 2004.

Description of Our Indebtedness

Continental Gas, Inc.

As of December 31, 2004, Continental Gas, Inc. had a $25 million term loan and a $10 million revolving credit facility. As of December 31, 2004, $15.1 million was outstanding under the term loan facility, bearing interest at 4.9%, and there were no outstanding borrowings under the revolving loan facility. The term loan facility included quarterly principal installments of $0.6 million. Proceeds from our initial public offering were used to retire all amounts outstanding under this facility and this facility was terminated.

Hiland Partners, LLC

As of December 31, 2004, Hiland Partners, LLC had a $25.0 million credit facility solely related to the Bakken gathering system, which we did not assume, and a $10.0 million term loan, which we assumed. As of December 31, 2004, $9.4 million was outstanding under the $10 million term loan, bearing interest at 4.9%. The term loan included monthly principal installments of $0.3 million. Proceeds from our initial public offering were used to retire all amounts outstanding under the term loan.

Credit Facility

Concurrently with the closing of our initial public offering, we established a $55.0 million credit facility through our operating company that consists 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”).

We have the right, no more than once in each fiscal year, to increase the size of the revolving acquisition facility; provided that each such increase shall be at least $10.0 million and in no event may the amount of the revolving acquisition facility exceed $82.5 million in the aggregate, and provided further that at the time of such request no default has occurred or would result due to such increase and subject to additional conditions set forth in the credit 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 ½ 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 4.0:1.0;

· a minimum interest coverage ratio of 3.0:1.0; and

· minimum tangible net worth of $55.0 million.

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 $0.

As of March 14, 2005, we had no indebtedness outstanding under the credit facility.

Recent Accounting Pronouncements

In June 2001, FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations” which 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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with early adoption permitted. We adopted the standard effective January 1, 2003. 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. Prior to SFAS 143, we had not recorded an obligation for these costs due to its 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 $2.6 million and $1.0 million, respectively, as a result of our 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 has been accounted for through a cumulative effect adjustment that amounted to $1.6 million pretax increase to net income recorded on January 1, 2003. The increase in expense resulting from the accretion of the asset retirement obligation and the depreciation of the additional capitalized plant, pipeline, and well costs is expected to be substantially offset by the decrease in depreciation from our consideration of the estimated salvage values in the depreciation calculation.

In October 1995, the FASB issued SFAS No. 123 “Share-Based Payments” which was revised in December 2004 (collectively, “FASB 123R”). FASB 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 be required to apply SFAS 123R as of the first interim period beginning on or after July 1, 2005. Early adoption is permitted and we expect to apply the Statement beginning January 1, 2005. We had no options outstanding as of December 31, 2004.

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, you should 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 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;

· 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, 2004 and 2002.

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 are recognized when earned ratably as due under the lease. Revenues from oil and gas production (discontinued operations) are recorded in the month produced and title is transferred to the purchaser. Under the compression services agreement that we entered into with Continental Resources, Inc. in connection with our offering, revenues will be recognized when the services under the agreement are performed. For a description of this service agreement, please read “—Our Contracts—Compression Services Agreement.”

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 the minimum quarterly distribution.

We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. 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;

· 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.

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 gathering system. 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, 2004, Continental Resources, Inc., Chesapeake Energy Corporation and Range Resources Corporation supplied us with approximately 37.8%, 26.8% and 15.3%, 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 $4.54 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 $0.94 per gallon to a low of $0.53 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, which ever is applicable, as the price of natural gas and NGLs fluctuates. For a detailed discussion of these contracts, please read “Item 7. 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.

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 Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or 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 non-proprietary 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. Please read “Items 1. and 2. Business and Properties—Regulation.”

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) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the discharge of waste from our facilities and (iii) the Comprehensive Environmental, Response Compensation and Liability Act of 1980, or 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 assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the Clean Air Act, RCRA, CERCLA and the federal Water Pollution Control Act of 1972, also known as the Clean Water Act, 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. Please read “Items 1. and 2. Business and Properties—Environmental Matters.”

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we may grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems, and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and 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 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.

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 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 strategy 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.

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 will limit our ability to make distributions to you and may limit our ability to capitalize on acquisitions and other business opportunities.

Our bank credit facility contains covenants limiting our ability to make distributions. In addition, our bank credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our bank credit facility contains covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

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 compressor 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, make acquisitions, reduce debt or for other purposes.

The credit markets recently have experienced 50-year record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. 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 for other purposes.

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.

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 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.” For the year ended December 31, 2004, a $0.10 per MMBtu increase in the price of natural gas combined with a $0.01 per gallon increase in NGL prices would have increased our total pro forma segment margin by $218,993, whereas a $0.10 per MMBtu decrease in the price of natural gas offset by a $0.01 per gallon increase in NGL prices would have increased our total pro forma segment margin by $76,639. In addition, for the year ended December 31, 2004, a $0.10 per MMBtu increase in the price of natural gas offset by a $0.01 per gallon decrease in NGL prices would have decreased our total pro forma segment margin by $17,734, whereas a $0.10 per MMBtu decrease in the price of natural gas combined with a $0.01 per gallon decrease in NGL prices would have decreased our total pro forma segment margin by $225,322. 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.

Interest Rate Risk. We are exposed to changes in interest rates as a result of our credit facility, which has floating interest rates. We had no indebtedness outstanding under our credit facility at March 14, 2005.

Credit Risk. Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. BP Energy Company and OGE Energy Resources, Inc. were our largest customers for the year ended December 31, 2004, accounting for approximately 29.5% and 26.1%, respectively, of our pro forma revenues. Consequently, changes within BP Energy Company’s or OGE Energy Resources, Inc.’s operations have the potential to impact, both positively and negatively, our credit exposure.

Item 8. Financial Statements and Supplementary Data

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.

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 2004 that would need to be reported on Form 8-K that have not been previously reported.

PART III

Item 10. Directors and Executive Officers of the Registrant

Hiland Partners GP, LLC, as our general partner, will manage our operations and activities on our behalf. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of Hiland Partners GP, LLC or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.

At least two members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine 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.

In addition, we have an audit committee of two independent directors that reviews our external financial reporting, recommends engagement of our independent auditors and reviews procedures for internal auditing and the adequacy of our internal accounting controls. In accordance with the rules of the Nasdaq National Market, we will appoint an additional independent director to the audit committee no later than February 10, 2006. We also have a compensation committee, that oversees compensation decisions for the officers of our general partner as well as the compensation plans described below.

The Board of Directors of Hiland Partners GP, LLC has determined that Messrs. Greenwood and Doherty meet the applicable criteria for independence under the currently applicable rules of the Nasdaq National Market and under the Exchange Act. These directors serve as the members of our audit, conflicts, and compensation committees. Mr. Greenwood serves as the Chairman of the audit committee.

Since we did not complete our initial public offering until February 15, 2005, the Board of Directors of Hiland Partners GP, LLC did not hold any meetings in 2004.

In compliance with the rules of the NASDAQ National Market, the members of the board of directors named below will appoint at least one additional independent member by February 10, 2006. Thereafter, we are generally required to have at least three independent directors serving on our board at all times.

We expect that our operational personnel will be employees of our general partner or its affiliates. The officers of our general partner will spend substantially all of their time managing our business and affairs.

Directors and Executive Officers of Hiland Partners GP, LLC

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	59	Chairman of the Board of Directors
Randy Moeder	44	Chief Executive Officer, President and Director
Ken Maples	42	Chief Financial Officer, Vice President—Finance, Secretary and Director
Clint Duty	45	Vice President—Operations and Engineering
Michael L. Greenwood	49	Director
Edward D. Doherty	69	Director

Harold Hamm was elected Chairman of the Board of Directors of our general partner in October 2004. 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, Mr. Hamm has served as President and Chief Executive Officer and a director of Continental Resources, Inc. and currently serves as Chairman of its Board of Directors. Mr. Hamm is a member of the board of directors of Oklahoma Independent Petroleum Association and currently is Vice President of the western region. He is the founder and served as Chairman of the Board of Directors of Save Domestic Oil, Inc. Currently, Mr. Hamm is President of the National Stripper Well Association, and serves on the Executive Boards of the Oklahoma Independent Petroleum Association and the Oklahoma Energy Explorers.

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 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. 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.

Michael L. Greenwood. Mr. Greenwood has served as a director of our general partner, as Chairman of the Audit Committee and as a member of the conflicts and compensation committees of the Board of Directors of our general partner since February 2005. 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 holds a Bachelor of Science in Business Administration degree from Oklahoma State University and a Master of Business Administration degree from the University of Tulsa.

Edward D. Doherty. Mr. Doherty has served as a director of our general partner and as a member of the audit, conflicts and compensation committees of the Board of Directors of our general partner since February 2005. Mr. Doherty has been 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. 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 from Lafayette College and a Doctor of Jurisprudence from Columbia University School of Law.

Audit Committee

Hiland Partners GP, LLC’s audit committee is composed of two directors who are not officers or employees of Hiland Partners, LP or any affiliates of the general partner. 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, 2004

Management of Hiland Partners, LP is responsible for Hiland Partners, LP’s internal controls and the financial reporting process. Grant Thornton LLP, Hiland Partners, LP’s Independent Registered Public Accounting Firm for the year ended December 31, 2004, is responsible for performing an independent

audit of Hiland Partners, LP’s consolidated financial statements in accordance with generally accepted auditing standards and to issue a report thereon. The audit committee monitors and oversees these processes. The audit committee recommends to the board of directors the selection of Hiland Partners, LP’s independent registered public accounting firm.

The audit committee has reviewed and discussed Hiland Partners, LP’s audited consolidated financial statements with management and the independent registered public accounting firm. The audit committee has discussed with Grant Thornton LLP the matters required to be discussed by Statement on Auditing Standards No. 61, “Communications with Audit Committees.” The audit committee has received the written disclosures and the letter from Grant Thornton LLP required by Independence Standards Board Standard No. 1, “Independence Discussions with Audit Committees,” and has discussed with Grant Thornton LLP that firm’s independence.

The Audit Committee of the Board of Directors of our general partner subsequently ratified Grant Thornton LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of Hiland Partners, LP for the 2004 calendar year.

Fees paid to Grant Thornton LLP for 2004 are as follows:

	2004
Audit Fees(1)	$	539,215
Audit Related Fees	—
Tax Fees	—
All Other Fees	—
Total	$	539,215

(1) 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.

The audit committee of our general partner’s Board of Directors has adopted an audit committee charter, which is available on our website at www.hilandpartners.com. The charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. Since the audit committee was not formed until the completion of our initial public offering in February 2005, none of the services reported above were pre-approved by the audit committee. However, the engagement of Grant Thornton LLP for the 2004 audit was ratified by our Audit Committee.

Based on the foregoing review and discussions and such other matters the audit committee deemed relevant and appropriate, the audit committee recommended to the Board of Directors that the audited consolidated financial statements of Hiland Partners, LP, Continental Gas, Inc. and Hiland Partners, LLC be included in Hiland Partners, LP’s Annual Report on Form 10-K for the year ended December 31, 2004.

Members of the Audit Committee:
Michael L. Greenwood
Edward D. Doherty

Code of Ethics

Hiland Partners, LP has adopted a Code of Business Conduct and Ethics that applies to all officers, directors and employees. In addition, Hiland Partners, LP has adopted a separate Code of Ethics for the Chief Executive and Senior Financial Officers.

Available on our website at www.hilandpartners.com are copies of our Audit Committee Charter, Conflicts Committee Charter, Compensation Committee Charter, Code of Business Conduct and Ethics, and Code of Ethics for Chief Executive Officer and Senior Financial Officers, all of which also will be provided without charge upon written request to Ken Maples at Hiland Partners, LP, 205 West Maple, Suite 1100, Enid, Oklahoma 73701.

Compliance With Section 16(a) of the Securities Exchange Act of 1934

Since we did not complete our initial public offering until February 15, 2005, Section 16(a) of the Securities Exchange Act of 1934 did not apply during the year ended December 31, 2004 to our directors, executive officers and 10% unitholders. 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, Inc. currently provides us with certain general and administration services. For a description of these services, please read “Item 13. Certain Relationships and Related Party Transactions—Omnibus Agreement—Services.” In the omnibus agreement, Continental Resources, Inc. has agreed to continue to provide these services to us for two years after the offering, at the lower of Continental Resources, Inc.’s cost to provide the services or $50,000 per year.

Executive Compensation

We and our general partner were formed in October 2004. We have not accrued any obligations with respect to management incentive or retirement benefits for our general partners’ directors and officers for the 2004 fiscal year. Commencing upon completion of the initial public offering, Messrs. Moeder, Maples and Duty will receive an annual salary of $180,000, $140,000 and $127,000, respectively. In addition, 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. 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. 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. Upon completion of the initial public offering, we granted options to purchase 32,000, 20,000 and 20,000 common units to Messrs. Moeder, Maples and Duty, respectively. The options have an exercise price equal to $22.50 per unit, the initial public offering price, and will otherwise have the terms described below under “Long—Term Incentive Plan.”

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation. Directors who are not officers or employees of our general partner will

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) awards under our Long-Term Incentive Plan. In addition to the foregoing, each director who serves on a committee will receive $1,000 for each committee meeting attended, the chairman of our audit committee will receive an annual retainer of $5,000 and the chairmen of our other committees will receive an annual retainer of $2,500. In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

Long-Term Incentive Plan

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, who perform services for our general partner or its affiliates. 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.

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 in control of us or the 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. At the time of our initial pubic offering, we granted options to purchase an aggregate of 143,000 common units to employees, officers and directors of our general partner. The options have an exercise price equal to the initial public offering price. Under the unit option grant agreements, the options will 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.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth, as of March 10, 2005, the beneficial ownership of our units held by:

· each person who then 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		9.0	%		2,400,602		58.8	%		38.9	%
Harold Hamm DST Trust(2)(3)		101,442		3.7	%		990,440		24.3	%		16.1	%
Harold Hamm HJ Trust(2)(4)		67,627		2.5	%		660,293		16.2	%		10.7	%
Randy Moeder(1)		39,149		1.4	%		28,665		*			*
Ken Maples(1)		13,333		*			—		—			*
Clint Duty(1)		—		—			—		—			—
Michael L. Greenwood(1)		8,291		*			—		—			*
Edward D. Doherty(5)		—		—			—		—			—
All directors and executive officers as a group (6 persons)		306,645		11.3	%		2,429,267		59.5	%		40.2	%

* 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 beneficially owns 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) Mr. Doherty’s address is 3425 N. Central Expressway, Suite 700, Richardson, Texas 75080.

The following table shows, as of March 10, 2005, the beneficial ownership of our general partner.

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		—			—
Michael L. Greenwood		—			—
Edward D. Doherty		—			—
All directors and executive officers as a group (3 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 the three year period after the completion of our initial public offering.

(4) Represents an unvested Class B membership interest that vests in equal increments annually over the three year period after the completion of our initial public offering.

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 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 Class B Units and all of Mr. Maples’ Class B Units are unvested and will vest in equal increments annually over the three-year period after the completion of our initial public offering. 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.

The following table summarizes information about our equity compensation plans as of December 31, 2004:

Number of Securities to be
issued upon exercise of
outstanding options,
warrants and rights

Weighted average
exercise price of
outstanding options,
warrants and rights

Number of securities
remaining available
for future issuance under
equity compensation plans
(excluding securities
reflected)

Equity compensation plans approved by security holders

—

Equity compensation plans not approved by security holders

—

For more information about our Long-Term Incentive Plan, which was approved by our partners prior to our initial public offering and was adopted after December 31, 2004, refer to “Item 11. Executive and Director Compensation—Long-Term Incentive Plan.”

Item 13. Certain Relationships and Related Transactions

Our general partner and its affiliates owns 475,714 common units and 4,080,000 subordinated units representing a 65.7% limited partner interest in us. In addition, the general partner owns a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the ongoing operation and any liquidation of Hiland Partners, LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations.

Operational Stage
Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to the unitholders, including our general partner and its affiliates, as the holders of an aggregate 475,714 common units and 4,080,000 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.
		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $0.25 million on its 2% general partner interest and $8.2 million on their common and subordinated units.

Payments to our general partner and its affiliates		Our general partner and its affiliates will not receive any management fee or other compensation for the management of our business and affairs, but they will be 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. As the sole purpose of the general partner is to act as our general partner, we expect that substantially all of the expenses of our general partner will be incurred on our behalf and reimbursed by us or our subsidiaries. Our general partner will determine the amount of these expenses. Continental Resources, Inc. currently provides us with certain general and administration services. For a description of these services, please read “—Omnibus Agreement—Services” below. In the omnibus agreement, Continental Resources, Inc. has agreed to continue to provide these services to us for two years after the offering, at the lower of Continental Resources, Inc.’s cost to provide the services and $50,000 per year.
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Entered into in Connection with our Initial Public Offering

We and other parties have entered into various documents and agreements in connection with our formation and our initial public offering. These agreements were not the result of arm’s length negotiations, and they, or any of the transactions that they provide for, may not have been effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties.

Omnibus Agreement

On February 15, 2005, we entered into an omnibus agreement with Continental Resources, Inc., 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, Inc. will provide certain general and administrative services;

· Harold Hamm’s agreement not to compete and to cause his affiliates (including Continental Resources, Inc.) not to compete with us under certain circumstances;

· an indemnity by Continental Resources, Inc., 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, Inc. for liabilities associated with oil and gas properties conveyed by Continental Gas, Inc. to Continental Resources, Inc. by dividend; and

· our two-year exclusive option to purchase the Bakken gathering system owned by Hiland Partners, LLC.

Services

Continental Resources, Inc. currently provides 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.

In the omnibus agreement, Continental Resources, Inc. has agreed to continue to provide these services to us for two years after the offering, at the lower of Continental Resources, Inc.’s 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 will not apply to:

· the ownership and/or operation of the Bakken gathering system;

· 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.

HILAND PARTNERS, LP
UNAUDITED PRO FORMA BALANCE SHEET
DECEMBER 31, 2004

											As Adjusted
	Predecessor										for Formation
	Historical			Historical			Adjustments				and							Pro Forma
	Continental			Hiland			Formation and				Excluded			Adjustments				Hiland
	Gas, Inc.			Partners, LLC			Excluded Assets				Assets			Offering				Partners, LP
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	217		$	770		$	(987	)(a)		$	1		$	51,750	(d)		$	12,590
								1		(b)					(5,432		)(e)
															(24,428		)(f)
															(6,278		)(g)
															(3,023		)(g)
Accounts receivable:
Trade		9,663			1,863			(10,318		)(a)		1,208			—				1,208
Affiliates		758			579			(1,337		)(a)		—			—				—
		10,421			2,442			(11,655		)		1,208			—				1,208
Inventories		153			—			—				153			—				153
Other current assets		118			67			—				185			—				185
Total current assets		10,909			3,279			(12,641		)		1,547			12,589				14,136
Property and equipment, net		37,075			48,295			(28,150		)(a)		68,675			—				68,675
								11,455		(c)
Intangible assets, net		—			—			26,800		(c)		26,800			—				26,800
Other assets		1,191			118			(54		)(c)		1,255			(1,075		)(e)		2
															(178		)(f)
Total assets		$	49,175		$	51,692		$	(2,590	)		$	98,277		$	11,336			$	109,613
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable		$	5,649		$	5,530		$	(4,970	)(a)		$	6,209		$	—			$	6,209
Accounts payable-affiliates		2,998			415			(316		)(a)		3,097			—				3,097
Accrued liabilities		327			153			(86		)(a)		394			—				394
Current maturities of long-term debt		2,429			9,356			—				11,785			(11,785		)(f)		—
Distribution payable		—			—			3,023		(a)		3,023			(3,023		)(g)		—
Total current liabilities		11,403			15,454			(2,349		)		24,508			(14,808		)		9,700
Non-current liabilities:
Long-term debt		12,643			23,279			(23,279		)(a)		12,643			(12,643		)(f)		—
Asset retirement obligation		619			396			—				1,015			—				1,015
Capital:
Continental Gas, Inc.
Common Stock		1			—			(1		)(b)		—			—				—
Paid in capital		10			—			(10		)(b)		—			—				—
Retained earnings		24,499			—			(9,430		)(a)		—			—				—
								(15,069		)(b)
Hiland Partners, LLC
Members’ equity					12,563			(5,734		)(a)		—			—				—
								(6,829		)(b)
Limited partner interests:
Common units
Public unit holders		—			—			—				—			51,750		(d)		45,184
															(6,507		)(e)
															(59		)(f)
Organizers		—			—			8,763		(b)		8,763			(11		)(f)		2,474
					—							—			(6,278		)(g)
Subordinated units		—			—			49,658		(b)		49,658			(104		)(f)		49,554
General partner interest		—			—			1,690		(b)		1,690			(4		)(f)		1,686
Organizer investment		—			—			(38,201		)(b)
								38,201		(c)
Total partners’ equity		24,510			12,563			23,038				60,111			38,787				98,898
Total liabilities and partners’ equity		$	49,175		$	51,692		$	(2,590	)		$	98,277		$	11,336			$	109,613

See accompanying notes to the unaudited pro forma financial statements.

F-3

HILAND PARTNERS, LP
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2004

	Predecessor
	Historical				Historical				Adjustments				Pro Forma
	Continental				Hiland				Formation and				Hiland
	Gas, Inc.				Partners, LLC				Offering				Partners, LP
	(in thousands, except per unit data)
Revenues:
Midstream—Third parties		$	95,019			$	9,379			$	(1,898	)(a)		$	102,500
Midstream—Affiliates		3,277				1,102				—				4,379
Compression		—				3,854				—				3,854
Total revenues		98,296				14,335				(1,898		)		110,733
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		82,532				4,600				(1,548		)(a)		85,584
Operations and maintenance		4,933				2,080				(196		)(a)		6,817
Depreciation and amortization		4,127				2,311				2,894		(c)		9,021
										(311		)(a)
Gain on asset sales		(19		)		—				—				(19		)
General and administrative		1,082				97				—				1,179
Total operating costs and expenses		92,655				9,088				839				102,582
Operating income		5,641				5,247				(2,737		)		8,151
Other income (expense):
Interest and other income		40				1				—				41
Amortization of deferred loan costs		(102		)		(106		)		(178		)(f)		(386		)
Interest expense		(702		)		(661		)		1,223		(h)		—
										140		(a)
Total other income (expense)		(764		)		(766		)		1,185				(345		)
Net Income		$	4,877			$	4,481			$	(1,552	)		7,806
General partner interest in net income														156
Limited partner interest in net income														$	7,650
Basic and diluted net income per limited partner unit														$	1.13
Basic and diluted weighted average limited partner units outstanding														6,800

See accompanying notes to the unaudited pro forma financial statements.

F-4

CONTINENTAL GAS, INC. (PREDECESSOR)
STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2002			2003			2004
	(in thousands)
Cash flows from operating activities:
Net income	$	487		$	972		$	4,912
Adjustments to reconcile net income to net cash provided by operating activities:
Cumulative effect of change in accounting principle	—			(1,724		)	—
Depreciation and amortization	2,510			3,448			4,170
Change in asset retirement obligation	—			25			23
Amortization of deferred loan cost	—			24			102
Bad debt expense	(295		)	—			—
Property impairments	—			1,535			—
Loss (gain) on sale of assets	51			41			(19		)
(Increase) decrease in current assets:
Accounts receivable—trade	561			(4,349		)	(1,831		)
Accounts receivable—affiliates	(118		)	(168		)	(226		)
Inventories	(8		)	—			122
Other current assets	3			5			(113		)
Increase (decrease) in current liabilities:
Accounts payable	323			3,704			319
Accounts payable—affiliates	1,273			664			482
Accrued liabilities	22			287			16
Net cash provided by operating activities	4,809			4,464			7,957
Cash flows from investing activities:
Additions to property and equipment	(5,760		)	(5,389		)	(5,326		)
Assets of business acquired	—			(12,025		)	—
Proceeds from disposals of property and equipment	115			128			36
Net cash used in investing activities	(5,645		)	(17,286		)	(5,290		)
Cash flows from financing activities:
Borrowings from affiliate	1,491			13,598			—
Repayments to affiliates	(975		)	(17,089		)	—
Long-term borrowings from third parties	—			17,000			500
Repayments of long-term borrowings from third parties	—			—			(2,428		)
Increase in deferred loan costs	—			(297		)	(6		)
Increase in deferred offering costs	—			—			(1,012		)
Net cash provided by (used in) financing activities	516			13,212			(2,946		)
Increase (decrease) for the period	(320		)	390			(279		)
Beginning of period	426			106			496
End of period	$	106		$	496		$	217
Supplementary information
Cash paid for interest	$	61		$	239		$	787
Non cash investing and financing activities:
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
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	)

The accompanying notes are an integral part of these financial statements.

F-12

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies

Description of Business

Continental Gas, Inc. (“CGI” or “the Company”) was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. (“CRI”). The Company operates in one business, midstream, which is engaged in the gathering, compressing, dehydrating, treating, and processing of natural gas and fractionating natural gas liquids, or NGLs. The Company connects the wells of natural gas producers in its market areas to its gathering systems, treats natural gas to remove impurities, processes natural gas for the removal of NGLs and sells the resulting products to a variety of intermediate purchasers. The Company owns and operates three processing plants with associated compressor stations, fractionation facilities and approximately 650 miles of gathering pipeline. These plants and associated gathering systems are located in Oklahoma and North Dakota. The Company also owns three small gathering systems consisting of approximately 20 miles of pipeline and compressor stations. These gathering systems are located in Texas, Mississippi and Oklahoma.

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 does 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 are now affiliated corporations because of common ownership.

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

The Company considers all highly liquid investments with maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable

The majority of the 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. The Company has established various

F-14

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

procedures to manage its 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 the Company believes 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.

In December 2001, Enron Corporation and its subsidiaries (“Enron”) filed for bankruptcy protection. As a result of the Company’s review of subsequent financial information on Enron, the Company wrote off $295 in accounts receivable from Enron in the first quarter of 2002.

Inventories

Inventories consist primarily of compressors and associated equipment. Inventories are stated at the lower of cost or estimated net realizable value.

Concentration and Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents and receivables.

The Company places its cash and cash equivalents with high-quality institutions and in money market funds. The Company derives its revenue from customers primarily in the natural gas and utility industries. These industry concentrations have the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers could be affected by similar changes in economic, industry or other conditions. However, the Company believes that the credit risk posed by this industry concentration is offset by the creditworthiness of the Company’s customer base. The Company’s portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.

Fair Value of Financial Instruments

The Company’s financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, 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. The fair value of long-term debt approximates its carrying value due to the variable interest rate feature of such debt.

Long-Lived Assets

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company evaluates its long-lived 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

F-15

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

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 the Company’s long-lived assets has occurred, the Company must estimate the undiscounted cash flows attributable to the asset or asset group. The Company’s 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 Company’s products are located;

· the availability and prices of NGL products and competing commodities;

· the availability and prices of raw natural gas supply;

· the Company’s ability to negotiate favorable marketing agreements;

· the risks that third party oil and gas exploration and production activities will not occur or be successful;

· the Company’s 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 the Company’s cash flows, which could require the Company 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, 2002 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.

Derivatives

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. SFAS No. 133

F-16

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

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. The Company’s forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a one-month to five-year term.

Property and Equipment

The Company’s 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 23 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.

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 corporation formed under Subchapter S of the Internal Revenue Code, the Company is not generally subject to income taxes. Accordingly, taxable income of the Company is allocated to the shareholders who are responsible for payment of any income taxes thereon, and therefore, income taxes are not reflected in the financial statements.

Transportation and Exchange Imbalances

In the course of transporting natural gas and NGLs for others, the Company 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, 2003 and 2004, the Company had no imbalance receivables or payables.

F-17

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

Recent Accounting Pronouncements

SFAS No. 143, “Accounting for Asset Retirement Obligations”

In June 2001, FASB issued 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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with early adoption permitted. The Company adopted the standard effective January 1, 2003. The primary impact of this standard relates to dismantling and site restoration of certain of the Company’s plants and pipelines; and abandonment and plugging of oil and gas wells in which the Company participates (herein referenced as discontinued operations). Prior to SFAS 143, the Company had not recorded an obligation for these costs due to its 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 the Company 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 has been accounted for through a cumulative effect adjustment that amounted to $1.7 million increase to net income recorded on January 1, 2003. The increase in expense resulting from the accretion of the asset retirement obligation and the depreciation of the additional capitalized plant, pipeline, and well costs is expected to be substantially offset by the decrease in depreciation from the Company’s consideration of the estimated salvage values in the depreciation calculation.

The following table summarizes the Company’s activity related to asset retirement obligations:

		Amount
Asset Retirement Obligation, January 1, 2003			$	526
Plus:	Asset Retirement Obligation accretion expense		25
	Additions for new assets		95
Asset Retirement Obligation, December 31, 2003			646
Plus:	Asset Retirement Obligation accretion expense		23
Less:	Transfer of discontinued operations		(50		)
Asset Retirement Obligation, December 31, 2004			$	619

Pro forma asset retirement obligation at January 1, 2002 was $502. 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.

F-18

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

The following table presents the pro forma effect on net income for the years December 31, 2002 and 2003 as if SFAS 143 had been adopted prior to January 1, 2002.

	Years Ended December 31,
	2002				2003
Net income, as reported		$	487			$	972
Discontinued operations, net		(199		)		(246		)
Cumulative effect of change in accounting principle		—				(1,554		)
Asset retirement obligation accretion expense		(18		)		—
Asset retirement cost depreciation expense		(29		)		—
Reduction in depreciation expense on salvage value		60				—
Income (loss) from continuing operations, pro forma		301				(828		)
Discontinued operations, net		199				246
Cumulative effect of change in accounting principle, discontinued operations		—				(170		)
Asset retirement obligation accretion expense		(2		)		—
Asset retirement cost depreciation expense		(1		)		—
Reduction in depreciation expense on salvage value		6				—
Net income (loss), pro forma		$	503			$	(752	)

SFAS No. 123, “Share-Based Payment”

In October 1995, the FASB issued SFAS No. 123, “Share-Based Payments,” which was revised in December 2004 (collectively, “FASB 123R”). FASB 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.

The Company will be required to apply SFAS 123R as of the first interim period beginning on or after July 1, 2005. Early adoption is permitted. The Company expects to apply the Statement beginning January 1, 2005.

The Company has no options outstanding as of December 31, 2004.

F-19

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

Note 2: Property and Equipment

	As of December 31,
	2003		2004
Land	$	120	$	127
Pipelines and plants	46,971		53,745
Other	1,837		2,209
Oil and gas properties (discontinued)	4,718		—
	53,646		56,081
Less: accumulated depreciation and amortization	15,221		19,006
	$	38,425	$	37,075

Depreciation and amortization charged to expense, including discontinued operations, totaled $2,510, $3,448, and $4,170 for the years ended December 31, 2002, 2003 and 2004, respectively.

Note 3: Long-Term Debt

	As of December 31,
	2003		2004
Note payable—bank(a)	$	17,000	$	15,072
Less: current portion	2,429		2,429
Long-term portion	$	14,571	$	12,643

(a) On October 22, 2003, the Company closed a new $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. The initial availability of funds under the credit facility was $22.0 million, $17.0 million of which was a term loan facility. Prior to closing this new facility, the Company 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. Advances under either facility can be made, at the borrower’s election, as reference rate loans or LIBOR loans and, with respect to the LIBOR loans, for interest periods of one, two, three, or six months. Interest is payable on the reference rate loans monthly and on LIBOR loans at the end of the applicable interest period. The principal amount of the term loan facility is amortized on a quarterly basis through June 30, 2006, with the final payment due on September 30, 2006. The amount available under the revolving loan facility may be borrowed, repaid and reborrowed until maturity on September 30, 2006. Interest on reference rate loans is calculated with a reference to a rate equal to the higher of the reference rate of the bank or the federal funds rate plus 0.5%. Interest on LIBOR loans is calculated with reference to the London interbank offered interest rate. Interest accrues at the reference rate or the LIBOR rate, as applicable, plus the applicable margins. The margin is based on the then current senior debt to EBITDA ratio. The credit agreement requires quarterly mandatory prepayments on the term loan of $607 and 75% of excess cash flow. The credit facility is collateralized by a pledge of all the assets of the Company. As of December 31, 2004, the effective interest rate under the facility was 4.9%. The

F-20

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

credit agreement contains certain covenants. CGI must maintain a current ratio of not less than 1.0 to 1.0; interest charge coverage ratio of 3.0 to 1.0; fixed charge coverage ratio of 1.5 to 1.0; and a senior debt to EBITDA ratio of 3.25 to 1.0. As of December 31, 2004, CGI was in compliance with its financial covenants. The agreement limits CGI’s ability to assume further indebtedness, assume contingent liabilities, sell assets, make investments, cancel insurance, amend, waive, or terminate material contracts, redeem senior subordinated notes, merge or consolidate, distribute cash to owners, change its structure or ownership, or participate in speculative trading. It also limits transactions with affiliates. Please see Note 10 for a description of management’s retirement of this obligation.

Funds available for advances under the credit agreement totaled $3.0 million at December 31, 2004.

Maturities of long-term debt are as follows at December 31, 2004:

Year	Amount
2005	$	2,429
2006	$	12,643

Note 4: Lease Commitments

The Company leases office space from a related entity. See Note 8.

The Company leases certain facilities, pipelines and equipment under operating leases, most of which contain annual renewal options. For the years ended 2002, 2003 and 2004, rent expense was $292, $174 and $198, respectively, under these leases. At December 31, 2004, 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:

Year	Amount
2005		$	86
2006		92
2007		93
2008		92
2009		61
Thereafter		13
Total		$	437

F-21

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

Note 5: Acquisitions

On July 31, 2003, the Company 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 the Company’s credit agreement with CRI. The allocation of the purchase price was based on fair values of the assets as follows:

	Amount
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.

F-22

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

The unaudited pro forma information set forth below includes the operations of Carmen assuming the acquisition of Carmen by CGI occurred on January 1, 2003. The unaudited pro forma 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:

	Pro Forma For the Twelve Months Ended December 31, 2003
	Carmen For the Seven Months Ended July 31, 2003				CGI For the Year Ended December 31, 2003				Consolidated
Midstream revenue		$	14,534			$	76,018			$	90,552
Total operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		12,160				67,002				79,162
Operations and maintenance		462				3,714				4,176
Property impairment		—				1,535				1,535
Depreciation and amortization		414				3,304				6,223
Loss on asset sales		—				34				34
General and administrative		128				770				898
Total operating costs and expenses		13,164				76,359				92,028
Income (loss) from operations		1,370				(341		)		(1,476		)
Other income (expense):
Interest and other income		—				10				10
Amortization of deferred loan costs		—				(24		)		(24		)
Interest expense		(281		)		(473		)		(473		)
Total other		(281		)		(487		)		(487		)
Income (loss) from continuing operations		1,089				(828		)		(1,963		)
Discontinued operations, net		—				246				246
Income (loss) before cumulative effect of change in accounting principle		1,089				(582		)		(1,717		)
Cumulative effect of change in accounting principle		—				1,554				1,554
Net income (loss)		$	1,089			$	972			$	(163	)

Note 6: Commitments and Contingencies

As a part of the Carmen acquisition discussed in Note 5, the Company became obligated to issue a letter of credit in the amount of $1.5 million to a customer of Carmen. This letter of credit was maintained in force through January 2005. No advances or demands have been made against the letter of credit.

The Company has 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 $4.53, $4.47 and $4.49, respectively, for years 2005 through 2007. Such contracts have been designated as normal sales under SFAS No. 133 and are therefore not marked to market as derivatives.

F-23

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

The Company maintains a defined contribution retirement plan for its employees under which it makes discretionary contributions to the plan based on a percentage of eligible employees compensation. During 2002, 2003 and 2004, contributions to the plan were 5.0% of eligible employees’ compensation. Expense for the years ended December 31, 2002, 2003 and 2004 was $45, $54, and $70, respectively.

The Company and other affiliated companies participate jointly in a self-insurance pool (the “Pool”) covering health and workers’ compensation claims made by employees up to the first $150,000 and $500,000, respectively, per claim. Any amounts paid above these are reinsured through third party providers. Premiums charged to the Company are based on estimated costs per employee of the Pool. No additional premium assessments are anticipated for periods prior to December 31, 2004. Property and general liability insurance is maintained through third-party providers with a $100,000 deductible on each policy.

The Company is a party to various regulatory proceedings and may from time to time be a party to litigation that it believes will not have a materially adverse impact on the Company’s financial condition, results of operations or cash flows.

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. Management believes that compliance with federal, state or local environmental laws and regulations will not have a material adverse effect on the Company’s business, financial position or results of operations.

Note 7: Significant Customers and Suppliers

All revenues are domestic revenues. The following table presents the Company’s top midstream customers as a percent of total revenue for the periods indicated:

	For the Years Ended December 31,
	2002			2003			2004
Customer 1		32	%		17	%		—
Customer 2		22	%		19	%		29	%
Customer 3		12	%		9	%		5	%
Customer 4		10	%		7	%		10	%
Customer 5		—			28	%		33	%

F-24

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

All purchases are from domestic sources. The following table presents the Company’s top midstream suppliers as a percent of total midstream purchases for the periods indicated:

	For the Years Ended December 31,
	2002			2003			2004
Supplier 1 (affiliated company)		43	%		37	%		33	%
Supplier 2		21	%		20	%		—
Supplier 3		—			18	%		17	%
Supplier 4		—			—			33	%

Note 8: Related Party Transactions

The Company purchases natural gas and NGLs from affiliated companies. Purchases of product totaled $13.3 million, $26.2 million, and $27.6 million for the years ended December 31, 2002, 2003 and 2004, respectively.

The Company utilizes affiliated companies to provide services to its plants and pipelines and certain administrative costs. The total amount paid to these companies was $142, $193, and $183 during the years ended December 31, 2002, 2003 and 2004, respectively.

The Company leases office space under operating leases directly or indirectly from the principal stockholder. Rents paid associated with these leases totaled $31, $47, and $51 for the years ended December 31, 2002, 2003 and 2004, respectively.

Note 9: Discontinued Operations

During the first quarter of 2004, the Company 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 Company transferred all its interests in its oil and gas properties to CRI.

A summary of oil and gas operations follows:

	Years Ended December 31,
	2002			2003			2004
Revenues	$	591		$	604		$	266
Expenses	(188		)	(351		)	(165		)
Depreciation and amortization	(140		)	(170		)	(66		)
Loss on assets sales	(64		)	(7		)	—
Change in accounting principle	—			170			—
Net income	$	199		$	246		$	35
Net Assets	$	1,658		$	2,452		$	—
Associated Liabilities	$	81		$	235		$	—

F-25

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

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 Company 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.

Note 10: Selected Quarterly Financial Data—Unaudited

The following is a summary of selected quarterly financial data for the years ended December 31, 2003 and 2004:

	2003 Quarter
	1st		2nd		3rd			4th
Revenues	$	12,004	$	16,355	$	23,407		$	24,252
Operating income (loss)	108		405		(139		)	(715		)
Income (loss) from continuing operations	50		340		(314		)	(904		)
Income (loss) before cumulative effect of change in accounting principle	121		512		(288		)	(927		)
Net income (loss)	1,675		512		(288		)	(927		)

F-26

CONTINENTAL GAS, INC. (PREDECESSOR)
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003, AND 2004
(in thousands, unless otherwise noted)

	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
Income before cumulative effect of change in accounting principle	767		1,008		846		2,291
Net income	767		1,008		846		2,291

Note 11: Subsequent Events

In connection with the formation of Hiland Partners, LP (the “Partnership”) and its initial public offering on February 15, 2005, the assets and liabilities of the Company excluding certain working capital assets were contributed to the Partnership in exchange for 271 common units and 2,647 subordinated units of the Partnership. The Company intends to repay the existing bank debt of the Company from the proceeds of the Partnership’s initial public offering.

F-27

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies

Description of Business

Hiland Partners, LLC (“Hiland”) was formed in September 2000 as an Oklahoma limited liability company. Hiland operates in two businesses: midstream, which is engaged in the gathering, compressing, dehydrating, treating, processing and marketing of natural gas and fractionating natural gas liquids, or NGLs; and compression, which is engaged in providing air compression and water injection services for oil and gas secondary recovery operations that are ongoing in North Dakota.

Hiland connects the wells of natural gas producers in its market area to its gathering system, treats natural gas to remove impurities, processes natural gas for the removal of NGLs and sells the resulting products to a variety of intermediate purchasers. Hiland owns and operates one processing plant with associated compressor stations, fractionation facilities and approximately 150 miles of gathering pipeline in Wyoming and commenced operations of another processing plant and gathering system in Montana in November 2004.

Hiland leases several large compressors to an affiliated entity, Continental Resources, Inc. (“CRI”). Certain Hiland owners also own approximately 9% of CRI common stock. These compressors supply compressed air and water for use in a secondary oil recovery project in North Dakota for which CRI is the operator.

Principles of Consolidation

The consolidated financial statements include the accounts of Hiland Partners, LLC and its wholly owned subsidiary Hiland Energy Partners, LLC (collectively, “the Company”). All significant intercompany accounts have been eliminated.

Use of Estimates

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturity of three months or less at the time of purchase to be cash equivalents.

Accounts Receivable

F-32

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

offset. Credit losses are charged to income when accounts are deemed uncollectible, determined on a case-by-case basis when the Company believes 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.

Concentration and Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents and receivables.

Fair Value of Financial Instruments

Long-Lived Assets

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company evaluates its long-lived 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 a long-lived asset has occurred, the Company must estimate the undiscounted cash flows attributable to the asset or asset group. The 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

F-33

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

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 Company’s products are located;

· the availability and prices of NGL products and competing commodities;

· the availability and prices of raw natural gas supply;

· the Company’s ability to negotiate favorable marketing agreements;

· the risks that third party oil and gas exploration and production activities will not occur or be successful;

· the Company’s 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 the Company’s cash flows, which could require the Company to record an impairment of an asset.

Hiland does not believe any asset impairment has occurred and, accordingly, has not recognized any impairment charges in these financial statements.

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 compressor leasing operations are recognized when earned ratably as due under the lease.

Property and Equipment

The Company’s 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, 14 to 20 years for pipeline and processing plants, 10 years for compressors and associated equipment 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.

Environmental Costs

F-34

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

Income Taxes

As a limited liability company electing to be taxed as a partnership, Hiland is not subject to income taxes. Accordingly, taxable income of Hiland is allocated to the members who are responsible for payment of any income taxes thereon and therefore, income taxes are not reflected in the financial statements.

Transportation and Exchange Imbalances

Segment Reporting

In accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information,” the Company’s reportable business segments have been identified based on the differences in the products or services provided (see Note 8).

Limited Liability Company

Hiland was formed as a limited liability company in 2000 with a finite life of 40 years. Under the formation documents, the Company will cease to exist in 2040. Hiland has one class of members. Any member of the class may be designated as the manager. The Company structure generally shields its members from liability, unless the member elects to assume liability, e.g., note guarantees.

Recent Accounting Pronouncements

SFAS No. 143, “Accounting for Asset Retirement Obligations”

In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which 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. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, with early adoption permitted. The Company adopted the standard effective January 1, 2003. The primary impact of this standard relates to dismantling

F-35

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

and site restoration of the Company’s plants. Prior to SFAS 143, the Company had not recorded an obligation for these costs due to its 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 $293 and $366, respectively. The impact of adopting SFAS 143 has been accounted for through a cumulative effect adjustment that amounted to $73 decrease to net income recorded on January 1, 2003.

The following table summarizes activity related to asset retirement obligations:

Pro forma asset retirement obligation at January 1, 2002 was $352. The effect of the change in accounting principle for the year ended December 31, 2003 was a reduction of net income of $88, including $15 accretion of the asset retirement obligation.

The following table presents the pro forma effect on net income for the years December 31, 2002 and 2003 as if SFAS 143 had been adopted prior to January 1, 2002.

	Years Ended December 31,
	2002				2003
Net income, as reported		$	1,514			$	3,415
Cumulative effect adjustment		—				73
Asset retirement obligation accretion expense		(14		)		—
Asset retirement cost depreciation expense		(23		)		—
Net income, pro forma		$	1,477			$	3,488

Note 2: Property and Equipment

	As of December 31,
	2003		2004
Pipelines and plant	$	7,693	$	36,249
Compressors	16,663		16,663
Other	68		130
	24,424		53,042
Less: Accumulated depreciation and amortization	2,451		4,747
	$	21,973	$	48,295

F-36

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

Depreciation and amortization charged to expense totaled $522, $1,669 and $2,296 for the years ended December 31, 2002, 2003 and 2004, respectively.

Note 3: Long-Term Debt

	As of December 31,
	2003		2004
Note payable—bank	$	14,166	$	32,635
Less: current maturities	3,336		9,356
Long-term portion	$	10,830	$	23,279

On December 6, 2002, Hiland executed a Credit Agreement in which a bank agreed to provide a $14.5 million senior secured credit facility. Borrowings under the credit facility are collateralized by liens on the assets of Hiland, personal guarantees of the member group and the personal guarantee of the primary stockholder of CRI. Borrowings under the credit facility bear interest, payable monthly, at a varying interest rate. Monthly repayment consists of interest plus a fixed principal payment of $200, plus an additional principal payment of 75% of EBITDA, as defined in the agreement, minus interest expense, capital expenditures and permitted tax distributions to members. The interest rate is the bank prime rate minus 25 basis points, but not less than 4.0% per annum. As of December 31, 2003, the interest rate was 4%. The credit facility matures on December 10, 2007. On April 16, 2003, Hiland executed a First Amendment to the Credit Agreement that increased the credit facility to $17.9 million and required an additional $78 fixed principal payment. On May 6, 2004, Hiland executed a Second Amendment to the Credit Agreement that increased the credit facility to $23.0 million. No other terms were changed. The credit agreement contains certain covenants. Hiland must maintain a current ratio, excluding current maturities of the credit facility, of not less than 1.0 to 1.0, and a fixed-charge ratio, tested quarterly, of not less than 1.10 to 1.0. The agreement limits Hiland’s ability to assume further indebtedness, assume contingent liabilities, sell assets, make investments, cancel insurance, merge or consolidate, distribute cash to owners, change its structure or ownership, or participate in speculative trading. It also limits transactions with affiliates.

As of December 31, 2003, there was no availability on the credit facility.

Effective October 7, 2004, Hiland, with its newly formed subsidiary, Hiland Energy Partners, LLC (HEP), executed a second restated loan agreement with a bank that increased the loan to include a $17,000 revolver and an $11,000 term loan, changed the maturity date to December 2005, and modified the interest rate to prime rate. Subsequently, on November 24, 2004, Hiland, HEP, and the bank executed loan agreements to divide the loan into two separate facilities. Hiland entered into a $25,000 note with a revolving period through July 20, 2005. The note matures on February 24, 2006 and bears interest at LIBOR, which was 4.9% as of December 31, 2004. Through July 20, 2005, monthly repayment consists of accrued interest; subsequently, monthly repayment consists of accrued interest plus a principal payment equal to 70% of monthly cash flow as defined in the agreement. Borrowings are collateralized by the assets of Hiland and guarantees of certain affiliates. The agreement contains covenants among which include maintenance of an interest coverage ratio of not less than 3 to 1. HEP entered into a $10,000 note that matures May 24, 2005 and bears interest at LIBOR. Monthly repayment consists of interest plus a fixed

F-37

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

principal payment of $278 plus 75% of excess monthly cash flow, as defined in the agreement. Borrowings are collateralized by the assets of HEP and guarantees of certain affiliates. The agreement contains covenants among which include maintenance of an adjusted current ratio and a fixed charge coverage ratio within certain specifications. As of December 31, 2004, Hiland and HEP were in compliance with its financial covenants. Please see Note 9 for a description of management’s intended retirement of HEP’s obligation.

As of December 31, 2004, credit availability on the $25 million facility was $1.7 million. The $10 million facility had no credit availability.

During the years ended December 31, 2002, 2003 and 2004, $0, $0, and $144 of interest was capitalized into plant construction.

Future maturities of long-term debt as of December 31, 2004 are as follows:

Years Ended December 31,	Amount
2005	$	9,356
2006	$	23,279

Note 4: Property on Lease

On December 9, 2002 and December 20, 2002, Hiland leased compressors that it acquired at a cost of $2.1 million and $9.9 million, respectively, to CRI. The operating leases have five-year terms but are subject to cancellation by the lessee after three years. At the end of the leases, the lessee can purchase the compressors for fair market value. Otherwise, the compressors will remain the property of Hiland. On August 20, 2003, additional compressors costing $4.7 million were acquired and leased to CRI on similar terms.

On December 31, 2003 and 2004, the carrying amount (at cost) of these compressors was $16.7 million. The accumulated depreciation was $1.3 million and $2.7 million, respectively.

Schedule of minimum lease payments to the Company due for the remaining non-cancellable lease term at December 31, 2004:

Years Ended December 31,	Amount
2005	$	3,722
2006	684
Total	$	4,406

Please see note 9 for a discussion of Hiland’s new contractual arrangement that replaces the operating leases described above.

Note 5: Commitments and Contingencies

The Company maintains a defined contribution retirement plan for its employees under which it makes discretionary contributions to the plan based on a percentage of eligible employees’ compensation. During 2002, 2003 and 2004, contributions to the plan were 5.0% of eligible employees’ compensation.

F-38

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

Expense for the years ended December 31, 2002, 2003 and 2004 was approximately $21, $23 and $23, respectively.

Hiland is a party to various regulatory proceedings and may from time to time be a party to litigation which it believes will not have a materially adverse impact on Hiland’s financial condition, results of operations or cash flows.

Note 6: Related Party Transactions

The Company purchases natural gas and NGLs from affiliated companies, principally CRI. Purchases of product totaled $0.6 million, $1.1 million, and $1.8 million for the years ended December 31, 2002, 2003 and 2004.

The Company utilizes unconsolidated affiliated companies to provide services to its plants and pipelines. The total amount paid to these companies was approximately $46, $32, and $76 during the years ended December 31, 2002, 2003 and 2004, respectively.

The Company contracts with unconsolidated affiliated companies to provide management services and certain administrative services. The total amount paid to these companies was approximately $120, $65, and $65 during the years ended December 31, 2002, 2003 and 2004, respectively.

The Company leases compressors to an affiliated company. Please see Note 4.

Note 7: Significant Customers and Suppliers

All revenues are domestic revenues and all lease revenue is from a single affiliated customer. The following table presents the top midstream customers as a percent of total revenues for the periods indicated:

	For the Years Ended December 31,
	2002			2003			2004
Customer 1		56	%		43	%		—
Customer 2		17	%		8	%		8	%
Customer 3		13	%		12	%		14	%
Customer 4		10	%		3	%		—
Customer 5		—			—			48	%

F-39

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

All purchases are from domestic sources. The following table presents the top midstream suppliers as a percent of total midstream purchases for the periods indicated:

	For the Years Ended December 31,
	2002			2003			2004
Supplier 1		41	%		40	%		34	%
Supplier 2		52	%		49	%		39	%
Supplier 3		—			—			22	%

Note 8: Business Segments

The Company’s operations are classified into two reportable segments:

(1) Midstream, which is engaged in the gathering, compressing, dehydrating, treating and processing of natural gas and fractionating NGLs.

(2) Compression, which is engaged in providing air compression and water injection equipment for CRI’s oil and gas secondary recovery operations that are ongoing in North Dakota.

The Company evaluates the performance of its segments and allocates resources to them based on operating income. The Company’s operations are conducted in the United States.

Years Ended December 31, 2002, 2003, and 2004

The table below presents information about operating income for the reportable segments for the years ended December 31, 2002, 2003, and 2004.

	Midstream				Compression				Total
Year Ended December 31, 2002
Revenues		$	5,480			$	244		$	5,724
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		1,439				—			1,439
Operations and maintenance		1,779				—			1,779
Depreciation and amortization		437				85			522
Loss on asset sales		36				—			36
General and administrative		156				—			156
Total operating costs and expenses		3,847				85			3,932
Income from operations		1,633				159			1,792
Other income (expense):
Interest and other income		27				—			27
Amortization of deferred loan costs		(73		)		—			(73		)
Interest expense		(214		)		(18		)	(232		)
Total other income (expense)		(260		)		(18		)	(278		)
Net income		$	1,373			$	141		$	1,514
Total assets		$	7,619			$	12,159		$	19,778
Capital expenditures		$	528			$	12,000		$	12,528

F-40

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

	Midstream				Compression				Total
Year Ended December 31, 2003
Revenues		$	7,262			$	3,300		$	10,562
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		2,826				—			2,826
Operations and maintenance		1,900				—			1,900
Depreciation and amortization		495				1,189			1,684
General and administrative		101				—			101
Total operating costs and expenses		5,322				1,189			6,511
Income from operations		1,940				2,111			4,051
Other income (expense):
Interest and other income		11				—			11
Interest expense		(72		)		(502		)	(574		)
Total other income (expense)		(61		)		(502		)	(563		)
Net income before cumulative change in accounting principle		1,879				1,609			3,488
Cumulative effect of change in accounting principle		(73		)		—			(73		)
Net income		$	1,806			$	1,609		$	3,415
Total assets		$	7,743			$	15,715		$	23,458
Capital expenditures		$	451			$	4,663		$	5,114

	Midstream				Compression				Total
Year Ended December 31, 2004
Revenues		$	10,481			$	3,854		$	14,335
Operating costs and expenses:
Midstream purchases (exclusive of items shown separately below)		4,600				—			4,600
Operations and maintenance		2,080				—			2,080
Depreciation and amortization		847				1,464			2,311
General and administrative		97				—			97
Total operating costs and expenses		7,624				1,464			9,088
Income from operations		2,857				2,390			5,247
Other income (expense):
Interest and other income		1				—			1
Amortization of deferred loan costs		(106		)		—			(106		)
Interest expense		(144		)		(517		)	(661		)
Total other income (expense)		(249		)		(517		)	(766		)
Net income		$	2,608			$	1,873		$	4,481
Total assets		$	37,767			$	13,925		$	51,692
Capital expenditures		$	24,781			$	—		$	24,781

F-41

HILAND PARTNERS, LLC
NOTES TO FINANCIAL STATEMENTS (Continued)
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004
(in thousands, unless otherwise noted)

Note 9: Subsequent Events

On January 27, 2005, Hiland executed a First Amendment to the Restated Loan Agreement that increased the $25 million note an additional $5 million to $30.0 million. No other terms were changed.

In connection with the formation of Hiland Partners, LP (the “Partnership”) and its initial public offering on February 15, 2005, the assets and liabilities of the Company excluding certain working capital assets and assets, liabilities, and operations relating to the Bakken gathering system were contributed to the Partnership in exchange for 149 common units and 1,433 subordinated units of the Partnership. The Company intends to repay the existing bank debt of the Company, excluding the debt of the Bakken plant and gathering system, from the proceeds of the Partnership’s initial public offering.

Also on February 15, 2005 and in conjunction with the initial public offering, Hiland and CRI entered into a new contractual arrangement where Hiland will provide air compression and water injection services for CRI’s oil and gas secondary recovery operations that are ongoing in North Dakota for a four year period with a month-to-month renewal option unless cancelled by either party. The new arrangement replaces the operating leases described in Note 4 above.

F-42

DELAWARE		71-0972724
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
205 West Maple, Suite 1100 Enid, Oklahoma		73701
(Address of principal executive offices)		(Zip code)

Exhibit Number		Description
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
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
10.1	—	Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and MidFirst Bank
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.
†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))
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
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
10.11*	—	Director’s Compensation Summary
19.1	—	Code of Ethics for Chief Executive Officer and Senior Finance Officers
21.1	—	List of Subsidiaries of Hiland Partners, LP
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

	HILAND PARTNERS, LP
	By: Hiland Partners GP, LLC, its general partner
	By:	/s/ RANDY MOEDER
		Randy Moeder
		Chief Executive Officer, President and Director

Hiland Partners, LP Unaudited Pro Forma Financial Statements:
Introduction		F-2
Unaudited Pro Forma Balance Sheet as of December 31, 2004		F-3
Unaudited Pro Forma Statement of Operations for the Year Ended December 31, 2004		F-4
Notes to Unaudited Pro Forma Financial Statements		F-5
Continental Gas, Inc. Financial Statements:
Report of Independent Registered Public Accounting Firm		F-9
Balance Sheets as of December 31, 2003 and December 31, 2004		F-10
Statements of Operations for the Years Ended December 31, 2002, 2003 and 2004		F-11
Statements of Cash Flows for the Years Ended December 31, 2002, 2003 and 2004		F-12
Statement of Changes in Stockholders’ Equity as of December 31, 2002, 2003 and 2004		F-13
Notes to Financial Statements		F-14
Hiland Partners, LLC Financial Statements:
Report of Independent Registered Public Accounting Firm		F-28
Balance Sheets as of December 31, 2003 and December 31, 2004		F-29
Statements of Operations and Changes in Members’ Equity for the Years Ended December 31, 2002, 2003 and 2004		F-30
Statements of Cash Flows for the Years Ended December 31, 2002, 2003 and 2004		F-31
Notes to Financial Statements		F-32
Hiland Partners, LP Balance Sheet:
Report of Independent Registered Public Accounting Firm		F-43
Balance Sheet as of December 31, 2004		F-44
Note to Balance Sheet		F-45

Items 1. and 2.	Business and Properties	3
Item 3.	Legal Proceedings	20
Item 4.	Submission of Matters to a Vote of Security Holders	20
Item 5.	Market for Registrant’s Common Units and Related Stockholder Matters	21
Item 6.	Selected Historical and Pro Forma Financial and Operating Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	57
Item 8.	Financial Statements and Supplementary Data	57
Item 9.	Changes in and Disagreements on Accounting and Financial Disclosure	57
Item 9A.	Controls and Procedures	57
Item 9B.	Other Information	58
Item 10.	Directors and Executive Officers of the Registrant	59
Item 11.	Executive and Director Compensation	63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	66
Item 13.	Certain Relationships and Related Transactions	68
Item 14.	Principal Accountant Fees and Services	72
Item 15.	Exhibits and Financial Statement Schedules	72

	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,
Ken Maples		Vice President—Finance, Secretary and
		Director
/s/ MICHAEL L. GREENWOOD		Director
Michael L. Greenwood
/s/ EDWARD D. DOHERTY		Director
Edward D. Doherty

		Common			Paid In			Retained
	Shares	Stock			Capital			Earnings			Total
	(in thousands, except share amounts)
Balance, December 31, 2001	1,000		$	1		$	10	$	20,269		$	20,280
Net income	—		—			—		487			487
Balance, December 31, 2002	1,000		1			10		20,756			20,767
Net income	—		—			—		972			972
Balance, December 31, 2003	1,000		1			10		21,728			21,739
Net income	—		—			—		4,912			4,912
Transfer of discontinued operations to parent company	—		—			—		(2,141		)	(2,141		)
Balance, December 31, 2004	1,000		$	1		$	10	$	24,499		$	24,510

Assets
Cash	$	1,000
Total Assets	$	1,000
Partners’ Equity
Partners’ equity:
Limited partner	$	980
General partner	20
Total partners’ equity	$	1,000