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UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-K

|ý                                           | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|------------------------------------------- | ----------------------------------------------------------------------------------------
|o                                           | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|For the fiscal year ended December 31, 2007

Commission file number: 000-51120

Hiland Partners, LP(Exact name of Registrant as specified in its charter)

|DELAWARE(State or other jurisdiction of
incorporation or organization)            |  | 71-0972724(I.R.S. Employer Identification No.)
|--------------------------------------------------------------------------------- |  | ----------------------------------------------
|205 West Maple, Suite 1100
Enid, Oklahoma(Address of principal executive offices) |  | 73701(Zip code)                               
|(580) 242-6040Registrant's telephone number including area code                  

Securities registered pursuant to Section 12(b) of the Act:

Title of Class

Name of each exchange on which registeredCommon Limited Partner Units

The NASDAQ Stock Market, LLC


Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of Securities
Act. Yes o    No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of
Act. Yes o    No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ý    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. ý

Indicate by check whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

|Large accelerated filer o |  | Accelerated filer ý |  | Non-accelerated filer o (Do not check if a smaller reporting company) |  | Smaller reporting company o
|------------------------- |  | ------------------- |  | --------------------------------------------------------------------- |  | ---------------------------

Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o    No ý

The aggregate market value of common limited partner units held by non-affiliates of the registrant was approximately $212.9 million on
June 30, 2007 based on the closing price of $54.50 on the Nasdaq National Market.

At
March 7, 2008, there were 5,226,362 common units and 4,080,000 subordinated units outstanding.

DOCUMENTS
INCORPORATED BY REFERENCE: None



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TABLE OF CONTENTS



|                |  | Part I                                                                                                        |  |   
|--------------- |  | ------------------------------------------------------------------------------------------------------------- |  | --
|Items 1. and 2. |  | Business and Properties                                                                                       |  | 3 
|Item 1A.        |  | Risk Factors                                                                                                  |  | 23
|Item 1B         |  | Unresolved Staff Comments                                                                                     |  | 41
|Item 3.         |  | Legal Proceedings                                                                                             |  | 41
|Item 4.         |  | Submission of Matters to a Vote of Security Holders                                                           |  | 41
|                |  | Part II                                                                                                       |  |   
|Item 5.         |  | Market for Registrant's Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities |  | 42
|Item 6.         |  | Selected Historical Financial and Operating Data                                                              |  | 44
|Item 7.         |  | Management's Discussion and Analysis of Financial Condition and Results of Operations                         |  | 47
|Item 7A.        |  | Quantitative and Qualitative Disclosures about Market Risk                                                    |  | 72
|Item 8.         |  | Financial Statements and Supplementary Data                                                                   |  | 74
|Item 9.         |  | Changes in and Disagreements on Accounting and Financial Disclosure                                           |  | 74
|Item 9A.        |  | Controls and Procedures                                                                                       |  | 74
|Item 9B.        |  | Other Information                                                                                             |  | 74
|                |  | Part III                                                                                                      |  |   
|Item 10.        |  | Directors and Executive Officers of the Registrant                                                            |  | 75
|Item 11.        |  | Executive Compensation                                                                                        |  | 81
|Item 12.        |  | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters                 |  | 93
|Item 13.        |  | Certain Relationships and Related Transactions                                                                |  | 94
|Item 14.        |  | Principal Accountant Fees and Services                                                                        |  | 97
|                |  | Part IV                                                                                                       |  |   
|Item 15.        |  | Exhibits and Financial Statement Schedules                                                                    |  | 98

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PART I

Items 1. and 2.    Business and Properties

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. References to "Hiland Holdings" refer to Hiland Holdings GP, LP. References to "our general
partner" refer to Hiland Partners GP, LLC.

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 Continental Resources, Inc. ("CLR"), a publicly traded exploration
and production company controlled by affiliates 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 segment, we provide compressed air and water to CLR, an exploration and production company controlled by affiliates of our general partner. CLR 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 14 natural gas gathering systems with approximately 2,024 miles of gas gathering pipelines, five natural gas processing plants, seven natural gas treating
facilities and three NGL fractionation facilities. Our compression assets consist of two air compression facilities and a water injection plant.

Recent Developments

Refinancing of Our Credit Facility.On February 6, 2008, we completed a fourth amendment to our existing credit
agreement to increase our borrowing base by $50 million from $250 million to $300 million and revise certain covenants. For a more complete discussion of our credit facility,
please see "Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesCredit Facility."

Officer Selection.On February 4, 2008, Mr. Matthew S. Harrison was appointed Vice President of Business
Development.

Distribution Increase.On January 25, 2008, we declared a cash distribution for the fourth quarter of 2007. This
declared quarterly distribution on our common and subordinated units increased to $0.795 per unit (an annualized rate of $3.18 per unit) from our most recent distribution of $0.755 per unit (an
annualized rate of $3.02 per unit). This represents a 5.3% increase over the prior quarter and an 11.6% increase over the distribution for the same quarter of the prior year. The distribution was paid
on February 14, 2008 to unitholders of record on February 4, 2008. Under our partnership agreement, generally our general partner is entitled to 15% of the amount we distribute to each
unitholder in excess of $0.495 per unit per quarter up to $0.5625 per unit per quarter, 25% of the amount we distribute to each unitholder in excess of $0.5625 per unit per quarter up to $0.675 per
unit per quarter and 50% of the excess over $0.675 per unit per quarter.

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Midstream Segment

Our midstream operations consist of the following:



Our
midstream assets include the following:



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Our
midstream revenues represented 98%, 98% and 97% of our total revenues for the years ended December 31, 2007, 2006 and 2005, respectively.

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The
following table contains certain information regarding our gathering systems as of or for the year ended December 31, 2007:

|Asset                           |  | Type                                                  |  | Length (Miles) |  | Wells Connected |  | Throughput Capacity(1) |  | Throughput Average(1) |     | Capacity Utilization |   | Percent of Total Segment Margin |  
|------------------------------- |  | ----------------------------------------------------- |  | -------------- |  | --------------- |  | ---------------------- |  | --------------------- | --- | -------------------- | - | ------------------------------- | -
|Eagle Chief gathering system    |  | Gathering pipelines                                   |  | 604            |  | 468             |  | 35,500                 |  | 29,449                |     | 83.0                 | % |                                 |  
|                                |  | Mix Refrigeration/JT Plant Constructed in 1995        |  |               |  |                |  | 35,000                 |  | 29,449                |     | 84.1                 | % | 17.1                            | %
|Bakken gathering system         |  | Gathering pipelines                                   |  | 365            |  | 273             |  | 25,000                 |  | 22,028                |     | 88.1                 | % |                                 |  
|                                |  | Refrigeration Plant Constructed in 2004               |  |               |  |                |  | 25,000                 |  | 22,028                |     | 88.1                 | % |                                 |  
|                                |  | Fractionation facility (Bbls/d)                       |  |               |  |                |  | 6,500                  |  | 3,397                 |     | 52.3                 | % | 33.6                            | %
|Worland gathering system        |  | Gathering pipelines                                   |  | 153            |  | 95              |  | 8,000                  |  | 2,649                 |     | 33.1                 | % |                                 |  
|                                |  | Refrigeration PlantConstructed in mid 1980's         |  |               |  |                |  | 8,000                  |  | 2,649                 |     | 33.1                 | % |                                 |  
|                                |  | Treating facility                                     |  |               |  |                |  | 8,000                  |  | 2,649                 |     | 33.1                 | % |                                 |  
|                                |  | Fractionation facility (Bbls/d)                       |  |               |  |                |  | 650                    |  | 257                   |     | 39.5                 | % | 5.0                             | %
|Badlands gathering system       |  | Gathering pipelines                                   |  | 214            |  | 163             |  | 46,000                 |  | 7,113                 | (2) | 15.5                 | % |                                 |  
|                                |  | Cryogenic and Refrigeration PlantConstructed in 2007 |  |               |  |                |  | 40,000                 |  | 7,113                 | (2) | 17.8                 | % |                                 |  
|                                |  | Treating facility                                     |  |               |  |                |  | 40,000                 |  | 7,113                 | (2) | 17.8                 | % |                                 |  
|                                |  | Fractionation facility (Bbls/d)                       |  |               |  |                |  | 4,000                  |  | 459                   | (2) | 11.5                 | % | 10.2                            | %
|Matli gathering system          |  | Gathering pipelines                                   |  | 54             |  | 50              |  | 25,000                 |  | 13,382                |     | 53.5                 | % |                                 |  
|                                |  | Mix Refrigeration Plant Constructed in 2006           |  |               |  |                |  | 25,000                 |  | 13,382                |     | 53.5                 | % |                                 |  
|                                |  | Treating facility                                     |  |               |  |                |  | 20,000                 |  | 7,075                 |     | 35.4                 | % | 1.8                             | %
|Kinta Area gathering systems    |  | Gathering pipelines                                   |  | 588            |  | 711             |  | 180,000                |  | 132,550               |     | 73.6                 | % |                                 |  
|                                |  | Treating facilities                                   |  |                |  |                 |  | 40,000                 |  | 22,004                |     | 55.0                 | % | 21.1                            | %
|Woodford Shale gathering system |  | Gathering pipelines                                   |  | 29             |  | 16              |  | 25,000                 |  | 8,313                 | (3) | 33.3                 | % | 4.8                             | %
|Other Systems                   |  | Gathering pipelines                                   |  | 17             |  | 24              |  | 7,000                  |  | 2,710                 |     | 38.7                 | % | 0.6                             | %
|                                |  |                                                       |  |                |  |                 |  |                        |  |                       |     |                      |   |                                 |  
|                                |  | Total                                                 |  | 2,024          |  | 1,800           |  |                        |  |                       |     |                      |   | 94.2                            | %
|                                |  |                                                       |  |                |  |                 |  |                        |  |                       |     |                      |   |                                 |  

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Compression Segment

We provide air and water compression services to CLR for use in its oil and gas secondary recovery operations under a four-year, fixed-fee
contract (which we entered into in connection with our initial public offering) at our Cedar Hills compression facility, our Horse Creek compression facility and our water injection plant located next
to our Cedar Hills compression facility. These assets are located in North Dakota in close proximity to our Badlands gathering system. At the compression facilities, we compress air to pressures in
excess of 4,000 pounds per square inch, and at the water injection plant, we pump water to pressures in excess of 2,000 pounds per square inch. The air and water are delivered at the tailgate of our
facilities into pipelines operated by CLR and are ultimately utilized by CLR in its oil and gas secondary operations. The natural gas produced by CLR flows

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through
our Badlands gathering system. Our compression segment represented approximately 5.8% of our total segment margin for the year ended December 31, 2007. Our compression revenues
represented 2%, 2% and 3% of our total revenues for the years ended December 31, 2007, 2006 and 2005, respectively.

Financial Information About Segments

See Part II, Item 8Financial Statements and Supplementary Data.

Business Strategies

Our management team is committed to increasing the amount of cash available for distribution per unit by executing the following strategies:



Midstream Assets

Our natural gas gathering systems include approximately 2,024 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.

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Eagle Chief Gathering System

General.The Eagle Chief gathering system is located in northwest Oklahoma and consists of approximately 604 miles of natural
gas gathering pipelines, ranging from two inches to sixteen inches in diameter, and the Eagle Chief processing plant. The gathering system has a capacity of approximately 35,500 Mcf/d, and
average throughput was approximately 29,449 Mcf/d for the year ended December 31, 2007. There are eight gas compressor stations located within the gathering system, comprised of fifteen
units. The plant and compressor stations combined have an aggregate of approximately 17,000 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 227 miles of gathering pipelines. In the first quarter of 2007, we completed the installation of additional pipelines and compression facilities
at our Eagle Chief gathering system and increased our current system capacity from approximately 30,000 Mcf/d to approximately 35,500 Mcf/d.

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, depending on delivery points, may not be required to be processed to meet pipeline quality specifications when we sell into interstate markets. The plant has processing capacity of
approximately 35,000 Mcf/d. During the year ended December 31, 2007, the facility processed approximately 29,449 Mcf/d of natural gas and produced approximately
1,013 Bbls/d of NGLs.

Natural Gas Supply.As of December 31, 2007, 468 wells were connected to our Eagle Chief gathering system. These wells
are located in the Anadarko Basin of northwestern Oklahoma and we believe they generally have long lives. The primary suppliers of natural gas to the Eagle Chief gathering system are Chesapeake Energy
Corporation and CLR, which represented approximately 66.6% and 10.1%,
respectively, of the Eagle Chief gathering system's natural gas supply for the year ended December 31, 2007.

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 parties. In addition, some of
our contracts are for the life of the lease. Natural gas is purchased at the wellhead from the producers under percentage-of-proceeds contracts,
percentage-of-index contracts or fee-based contracts. For the year ended December 31, 2007, approximately 69.3%, 28.4% and 2.3% of our total wellhead volumes
at the Eagle Chief gathering system was derived from percentage-of-proceeds, percentage-of-index and fee-based contracts, respectively. For
a more complete discussion of natural gas purchase contracts, please read Item 7 "Management's Discussion and Analysis of Financial Condition and Results of OperationsOur Natural
Gas Purchase and Gathering Contracts."

Markets for Sale of Natural Gas and NGLs.The Eagle Chief gathering system has numerous market outlets for the natural gas
that we gather and NGLs that we produce on the system. The residue gas is sold at the tailgate of the Eagle Chief processing plant on the Oklahoma Gas Transportation pipeline to intrastate markets and
on the Panhandle Eastern Pipeline Company pipeline to interstate markets. Because the area connected to our Eagle Chief gathering system produces lean natural gas, we are able to bypass our Eagle
Chief processing plant by selling into the interstate markets when processing margins are unfavorable. The NGLs extracted from the gas at the Eagle Chief processing plant are transported by pipeline
to ONEOK Hydrocarbon Company's Medford facility for fractionation. We are currently selling the NGLs to ONEOK Hydrocarbon under a year-to-year contract.

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Our
primary purchasers of residue gas and NGLs on the Eagle Chief gathering system were OGE Energy Resources, Inc., ConocoPhillips Company, ONEOK Hydrocarbon, LP and
Tenaska Marketing Ventures, which represented approximately 33.0%, 24.8%, 23.0% and 7.4%, respectively, of the revenues from such sales for the year ended December 31, 2007.

Bakken Gathering System

General.The Bakken gathering system is located in eastern Montana and consists of approximately 365 miles of natural gas
gathering pipelines, ranging from three inches to twelve inches in diameter, the Bakken processing plant, which includes seven compressors and a fractionation facility. The gathering system has a
capacity of approximately 25,000 Mcf/d, and average throughput was approximately 22,028 Mcf/d for the year ended December 31, 2007. There are three gas compressor stations located
within the gathering system, comprised of five units. The compressor stations and plant combined have slightly over 10,600 horsepower.

We
acquired the Bakken gathering system in September 2005 in connection with our acquisition of Hiland Partners, LLC. The Bakken gathering system, including the Bakken processing
plant, was constructed during 2004 and commenced operations on November 8, 2004.

The
Bakken processing plant processes natural gas that flows through the Bakken gathering system to produce residue gas and NGLs. The plant has processing capacity of approximately
25,000 Mcf/d. For the year ended December 31, 2007, the facility processed approximately 22,028 Mcf/d of natural gas and produced approximately 2,336 Bbls/d of NGLs.

The
Bakken gathering system also includes a fractionation facility that separates NGLs into propane, butane and natural gasoline. The fractionation facility has a current capacity to
fractionate approximately 6,500 Bbls/d of NGLs. For the year ended December 31, 2007, the facility fractionated an average of approximately 3,397 Bbls/d to produce approximately
1,205 Bbls/d of propane, approximately 929 Bbls/d of butane and approximately 118 Bbls/d of natural gasoline. In the third quarter of 2007, we completed the expansion of our NGL
fractionation facilities at our Bakken processing plant to fractionate expected increased NGL volumes from both the Bakken processing plant and the Badlands processing plant.

Natural Gas Supply.As of December 31, 2007, 273 wells were connected to our Bakken gathering system. These wells,
which are located in the Williston Basin of Montana, primarily produce crude oil from the Bakken formation. The associated natural gas produced from these wells flows through our Bakken gathering
system. The primary suppliers of natural gas to the Bakken gathering system are Enerplus Resources (USA) Corporation, CLR and ConocoPhillips Company, which represented approximately 50.0%, 36.9% and
12.4%, respectively, of the Bakken gathering system's natural gas supply for the year ended December 31, 2007.

Substantially
all of the natural gas supplied to the Bakken gathering system is dedicated to us under three individually negotiated percentage-of-proceeds
contracts. Two of these contracts have an initial term of ten years and one is for the life of the lease. Under these contracts, natural gas is purchased at the wellhead from the producers. For a more
complete discussion of natural gas purchase contracts, please read Item 7 "Management's Discussion and Analysis of Financial Condition and Results of OperationsOur Natural Gas
Purchase and Gathering Contracts."

Markets for Sale of Natural Gas and NGLs.Residue gas derived from our processing operations is sold at the tailgate of the
Bakken processing plant on the Williston Basin Intrastate Pipeline to intrastate markets. Depending on prevailing market prices at each delivery point, we either sell our NGLs produced by our
fractionation facility to SemStream, L.P. at the tailgate of the plant or transport the same NGLs through our pipeline to a rail terminal and then sell to SemStream, L.P.

Our
primary purchasers of residue gas and NGLs on the Bakken gathering system were SemStream, L.P. and Montana-Dakota Utilities Co, which represented approximately 54.3%, and
38.0% respectively, of the revenues from such sales for the year ended December 31, 2007.

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Worland Gathering System

General.The Worland gathering system is located in central Wyoming and consists of approximately 153 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 2,649 Mcf/d for the year ended December 31, 2007. There are six gas compressor stations located
within the gathering system, comprised of eleven units. The plant and compressor stations have a total of nearly 5,500 horsepower installed.

The
Worland gathering system and the Worland processing plant were contributed to us on February 15, 2005 in connection with our formation and our initial public offering. This
gathering system, including the Worland processing plant, was originally built in the mid 1980s. A substantial portion of the equipment on the Worland gathering system, including portions of the
Worland processing plant 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, 2007, the
facility processed approximately 2,649 Mcf/d of natural gas and produced approximately 153 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 natural gasoline. The fractionation facility has a
capacity to fractionate approximately 650 Bbls/d of NGLs. For the year ended December 31, 2007, the facility fractionated an average of approximately 257 Bbls/d to produce
approximately 58 Bbls/d of propane and approximately 64 Bbls/d of a mixture of butane and natural gasoline.

Natural Gas Supply.As of December 31, 2007, 95 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 CLR and
Saga Petroleum, LLC., which represented approximately 55.1% and 36.9%, respectively, of the Worland gathering system's natural gas supply for the year ended December 31, 2007.

The
natural gas supplied to the Worland gathering system is generally dedicated to us under individually negotiated long-term contracts. Following the initial term of the
contracts, they 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
percentage-of-index contracts and fixed-fee contracts. For the year ended December 31, 2007, approximately 93.9% and 6.1% of our total wellhead volumes at
the Worland gathering system was derived from percentage-of-index contracts and fixed-fee contracts, respectively. For a more complete discussion of natural gas
purchase contracts, please read Item 7 "Management's Discussion and Analysis of Financial Condition and Results of OperationsOur Natural Gas Purchase and Gathering Contracts."

Markets for Sale of Natural Gas and NGLs.Residue gas derived from our processing operations is sold at the tailgate of the
Worland processing plant on the Williston Basin Intrastate Pipeline to intrastate markets. We sell the propane that is produced by our fractionation facility and the remaining NGL products to a
subsidiary of Kinder Morgan Energy Partners, L.P. at the tailgate of the plant.

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Our
primary purchasers of residue gas and NGLs on the Worland gathering system were Rainbow Gas Company, a Kinder Morgan Energy Partners, L.P. subsidiary and CLR, which
represented approximately
42.6%, 41.0% and 16.4%, respectively, of revenues from such sales on the Worland gathering system for the year ended December 31, 2007.

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 214 miles of
natural gas gathering pipelines, ranging from two inches to twelve inches in diameter, the Badlands processing plant, a natural gas treating facility, a fractionation facility and five gas compressor
stations. The total horsepower for the system was approximately 17,975 at December 31, 2007. The gathering system has a capacity of approximately 46,000 Mcf/d, and average throughput was
approximately 7,113 Mcf/d for the year ended December 31, 2007.

In
order to fulfill our obligations under an agreement with CLR to gather, treat and process additional natural gas, produced as a by-product of CLR's secondary oil recovery
operations, in the areas specified by the contract, we expanded our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. We completed the expansion of our
Badlands gathering system, the associated field gathering infrastructure and processing plant, which included the completion of our 40,000 Mcf/d nitrogen rejection plant during the third
quarter of 2007. As a result, gathering pipelines, processing plant, treating facility and fractionation facility throughput capacities increased significantly.

We
completed construction and commenced operation of the Badlands gathering system, including the original 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 40,000 Mcf/d. During the year ended December 31, 2007, the facility processed approximately 7,113 Mcf/d
of natural gas and produced approximately 459 Bbls/d of NGLs. Average throughput since the start up of the expanded field gathering infrastructure, processing plant and nitrogen rejection plant
from August 20, 2007 through the end of the year was approximately 15,988 Mcf/d of natural gas, which produced approximately 770 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. The Badlands treating facility has throughput capacity of 40,000 Mcf/d.

The
Badlands gathering system also includes a fractionation facility that separates NGLs into propane and a mixture of butane and natural gasoline. At December 31, 2007, the
fractionation facility had a capacity to fractionate approximately 4,000 Bbls/d of NGLs. For the year ended December 31, 2007, the facility fractionated an average of approximately
459 Bbls/d to produce approximately 215 Bbls/d of propane and approximately 173 Bbls/d of a mixture of butane and natural gasoline.

Natural Gas Supply.As of December 31, 2007, 163 wells were connected to our Badlands gathering system. These wells
are located in the Williston Basin of southwestern North Dakota and northwestern South Dakota and generally have long lives with predictable and steady flow rates. The primary suppliers of natural gas
to the Badlands gathering system are CLR and Luff Exploration Company, which represented approximately 83.8% and 10.2%, respectively, of the Badlands gathering system's natural gas supply for the year
ended December 31, 2007.

The
natural gas supplied to the Badlands gathering system is generally dedicated to us under individually negotiated long-term contracts. Our new agreement with CLR has an
initial term of 15 years. Under this agreement, we receive 50% of the proceeds attributable to residue gas and natural gas liquids sales as well as certain fixed fees associated with gathering
and treating the natural gas,

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including
a $0.60 per Mcf fee for the first 36.0 Bcf of natural gas gathered. Depending on the level of carbon dioxide, the contract allows us to charge a treating fee ranging from $0.093 to $0.193
per Mcf treated. This agreement replaces our existing agreement with CLR in the area as the new plant became operational. Following the initial term of the contracts, they generally continue on a year
to year basis, unless terminated by one of the producers. For these other agreements, natural gas is purchased at the wellhead from the producers under percentage-of-proceeds
arrangements. For a more complete discussion of natural gas purchase contracts, please read Item 7 "Management's Discussion and Analysis of Financial Condition and Results of
OperationsOur Natural Gas Purchase and Gathering Contracts."

Air Compression and Water Injection FacilitiesWe 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 our Badlands gathering system, we
currently provide air compression and water injection services to CLR 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 CLR for their secondary recovery operations or Williston Basin Pipeline Company. We sell the propane produced by our fractionation facility at the tailgate of the plant to
SemStream, L.P. The remaining NGL products are either sold to SemStream, L.P. at the tailgate of the plant, or the NGL products are trucked to the Bakken fractionation facility for
further fractionation, and then sold to SemStream, L.P.

Our
primary purchasers of the residue gas and NGLs from the Badlands gathering system were SemStream, L.P. and CLR, which represented approximately 86.7% and 13.3%, respectively,
of the revenues from such sales for the year ended December 31, 2007.

Matli Gathering System

General.The Matli Gathering System is located in central Oklahoma and consists of approximately 54 miles of natural gas
gathering pipelines, ranging from three inches to twelve inches in diameter, the Matli processing plant, and a natural gas treating facility and two gas compressor stations, all totaling approximately
7,300 horsepower. The gathering system has a capacity of approximately 25,000 Mcf/d, and average throughput was approximately 13,382 Mcf/d for the year ended December 31, 2007.

We
commenced operation of the Matli gathering system in 1999. During the fourth quarter of 2006, we completed the construction of a 25,000 Mcf/d natural gas processing facility
along our existing gas gathering system, which replaced our 10,000 Mcf/d processing facility we had constructed 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 current plant has
processing capacity of approximately 25,000 Mcf/d. During the year ended December 31, 2007, the facilities processed approximately 13,382 Mcf/d of natural gas and produced approximately
291 Bbls/d of NGLs. The old 10,000 Mcf/d natural gas processing facility is currently idle.

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. The throughput capacity on our Matli treating facility is approximately 20,000 Mcf/d.
During the year ended December 31, 2007, the facility treated approximately 7,075 Mcf/d of natural gas.

Natural Gas Supply.As of December 31, 2007, 50 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

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system
are CLR and Range Resources Corporation, which represented approximately 57.4% and 25.9%, respectively, of the Matli gathering system's natural gas supply for the year ended December 31,
2007.

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 five years with two years remaining on most of the contracts. Following the initial term, these contracts usually
continue on a year-to-year basis, unless terminated by one of the parties. Natural gas is purchased at the wellhead from the producers under fixed fee contract arrangements.
For a more complete discussion of natural gas purchase contracts, please read Item 7 "Management's Discussion and Analysis of Financial Condition and Results of OperationsOur
Natural Gas Purchase and Gathering 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. As part of our expansion project completed in late 2006, we converted an existing natural gas pipeline into a NGL pipeline and now
transport NGLs to the ONEOK Hydrocarbon Medford facility.

Our
primary purchasers of residue gas and NGLs on the Matli gathering system were OGE Energy Resources, Chevron Natural Gas and ONEOK Hydrocarbon, LP, which represented
approximately 55.2%, 19.2% and 15.1%, respectively, of the revenues from such sales for the year ended December 31, 2007.

Kinta Area Gathering Systems

General.The Kinta Area gathering systems, which we acquired from Enogex Gas Gathering, L.L.C. on May 1, 2006, are
located in eastern Oklahoma and consist of five separate natural gas gathering systems with 588 miles of natural gas gathering pipelines ranging from four inches to twelve inches in diameter, 25 gas
compressor units and one electric compressor unit capable of an aggregate of approximately 40,000 horsepower. An increasing portion of the natural gas supplied to the Kinta Area gathering systems has
high carbon dioxide content; consequently, during the first quarter of 2007, we installed four 10,000 Mcf/d capacity amine-treating facilities on two of the five sub systems to remove excess
carbon dioxide levels from the gas gathered by these gathering systems. The gathering system has a capacity of approximately 180,000 Mcf/d, and average throughput was 132,550 Mcf/d for
the year ended December 31, 2007. Our operations include gathering, dehydration, compression and treating of the natural gas supplied to the Kinta Area gathering systems and the redelivery of
the compressed natural gas for a fixed fee. We completed the installation of additional compression facilities to increase the capacity by approximately 5,000 Mcf/d on these gathering systems
in the fourth quarter of 2007.

Natural Gas Supply.As of December 31, 2007, approximately 711 wells were connected to our Kinta Area gathering
systems. These wells, which are located in the Arkoma Basin of eastern Oklahoma, primarily produce natural gas from the Atoka, Cromwell, Booch, Hartshorne, Spiro, Fanshaw and Red
Oak formations. The natural gas produced from these wells flows through our Kinta Area gathering systems. The primary suppliers of natural gas to this gathering system are BP America Production
Company, Chesapeake Energy Marketing, Inc. and Chevron North America Exploration and Production Co., which represented approximately 49.1%, 12.9% and 6.2%, respectively, of the Kinta
Area gathering system's natural gas supply for the year ended December 31, 2007.

The
Kinta Area gathering systems are located in an active drilling area. We believe that a high level of exploration and development activity in the area, including the Woodford Shale
play to the west of the existing system, 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. The natural gas supplied to the Kinta Area gathering systems is generally

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dedicated
under individually negotiated term contracts. The initial term of such agreements is generally three years.

The
natural gas purchased at the wellhead from the producers is under fixed-fee contract arrangements. The natural gas gathered in which we do not take title to the gas is
also under fixed-fee contract arrangements. For a more complete discussion of natural gas purchase contracts, please read Item 7 "Management's Discussion and Analysis of Financial
Condition and Results of OperationsOur Natural Gas Purchase and Gathering Contracts."

Markets for Sale and Delivery of Natural Gas.The residue gas derived from our Kinta Area gathering system is either sold or
delivered at the tailgate of the gathering system on the Enogex, Inc. pipeline to intrastate markets and on the Centerpoint Energy Gas Transmission pipeline to interstate markets. We sell our
purchased residue gas and deliver the residue gas we gather for third parties.

Our
primary purchasers of residue gas on the Kinta Area gathering system were BP Energy Company, Tenaska Marketing Ventures and ConocoPhillips Company, which represented approximately
21.4%, 21.1% and 8.4% respectively, of the revenues from such sales for the year ended December 31, 2007.

Woodford Shale Gathering System

General.The Woodford Shale gathering system is located in the Woodford Shale reservoir area in the Arkoma Basin of
southeastern Oklahoma, just to the west of our Kinta Area gathering systems. As of December 31, 2007 we had installed 29 miles of gathering pipelines and as of December 31, 2007, the
gathering system had a capacity of approximately 25,000 Mcf/d. Our Woodford Shale gathering system has two compressor stations comprised of six units with approximately 8,000 horsepower
installed.

Initial
production began on April 27, 2007 and from that date through December 31, 2007 throughput averaged approximately 8,313 Mcf/d of natural gas, which produced
approximately 649 Bbls/d of NGLs. Our current operations provide only gathering and compression services. Once completed, the gathering infrastructure will consist of field gathering,
compression and associated equipment, which will include more than 15,500 horsepower of compression to provide takeaway capacity in excess of 40,000 Mcf/d.

Natural Gas Supply.As of December 31, 2007, 16 wells were connected to our Woodford Shale gathering system, which
primarily produce natural gas from the Woodford shale formation. Presently, the supplier of natural gas to this gathering system is CLR, which provided all of the Woodford Shale gathering system's
natural gas supply for the year ended December 31, 2007.

The
natural gas purchased at the wellhead from the producers is under fixed-fee contract arrangements. For a more complete discussion of natural gas purchase contracts,
please read Item 7 "Management's Discussion and Analysis of Financial Condition and Results of OperationsOur Natural Gas Purchase and Gathering Contracts."

Markets for Sale of Natural Gas and NGLs.Residue gas derived from our Woodford Shale gathering system is delivered at the
tailgate of the gathering system to Enogex Gas Gathering, LLC for processing and NGL extraction. The residue gas is sold on Enogex, Inc. pipeline to intrastate markets. NGLs are sold at the tailgate
of Enogex Gas Gathering, LLC's plant to Enogex Products Corporation.

Our
primary purchasers of residue gas and NGLs on the Woodford Shale gathering system were Enogex Products Corporation, Tenaska Marketing Ventures and United Energy Trading, LLC,
which represented approximately 41.3%, 31.2% and 18.6%, respectively, of the revenues from such sales for the year ended December 31, 2007.

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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:



Compression Assets

We completed construction of our Cedar Hills compression facility and acquired the Horse Creek compression facility in 2002. The Horse Creek compression facility
is comprised of two units with an aggregate of approximately 5,300 horsepower. The Cedar Hills compression facility is comprised of ten units with an aggregate of approximately 40,000
horsepower. Our water injection plant has three pumps with a total of 900 horsepower.

At
the compression facilities, we compress air to pressures in excess of 4,000 pounds per square inch. At our water injection plant, water is produced from source wells located near the
water plant site. Produced water is run through a filter system to remove impurities and is then cooled prior to being pumped to pressures in excess of 2,000 pounds per square inch. The air and
water are delivered at the tailgate of our facilities into pipelines owned by CLR and are ultimately utilized by CLR in its oil and gas secondary recovery operations. For a description of the services
agreement we entered into with CLR in connection with our initial public offering, please read "Management's Discussion and Analysis of Financial Condition and Results of OperationsOur
ContractsCompression Services Agreement."

Credit Risks

Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result of nonperformance. OGE Energy
Resources, Inc., SemStream, L.P., ConocoPhillips, Inc. and Montana-Dakota Utilities Co. were our largest customers for the year ended December 31, 2007, accounting
for approximately 19%, 19%, 12% and 11%, respectively, of our revenues. Consequently, changes within one or more of these companies' operations have the potential to impact, both positively and
negatively, our credit exposure. Our counterparty for all of our derivative instruments as of December 31, 2007 is BP Energy Company.

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

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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 Atlas Pipeline
Partners, Mustang Fuel Corporation, and Duke Energy Field Services. Our primary competitor on the Bakken gathering system and the Badlands gathering system is Bear Paw Energy, and on the Matli
gathering system, our competitor is Enogex, Inc. Our primary competitor on the Kinta Area gathering systems is CenterPoint Energy Field Services. Our primary competitors on the Woodford Shale
gathering system are MarkWest Energy Partners, Enogex, Inc. and Copano Energy, L.L.C. 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:



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.

Regulation of Intrastate Natural Gas Transportation Pipelines.We do not own any pipelines that provide intrastate natural
gas transportation, so state regulation of pipeline transportation does not directly affect our operations. As with FERC regulation described above, however, state regulation of pipeline
transportation may influence certain aspects of our business and the market for our products.

Gathering Pipeline Regulation.Section 1(b) of the Natural Gas Act, or NGA exempts natural gas gathering facilities
from the jurisdiction of the FERC. We own a number of intrastate natural gas

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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 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. 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.

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. 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.

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Under
the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of
non-interstate pipelines and other natural gas market participants. The Commodity Futures Trading Commission, or the CFTC, also holds authority to monitor certain segments of the physical
and futures energy commodities market
pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas and NGLs, our gathering or transportation of these energy commodities, and any related hedging
activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial
enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we
violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

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:



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 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. While we
believe that we are in substantial compliance with current applicable federal and state environmental laws and regulations and that continued compliance with existing requirements will not have a
material adverse impact on our results of operations or financial condition, there is no assurance that this trend of compliance will continue in the future. Moreover, while we believe that the
various environmental activities in which we are presently engaged will not affect our operational ability to gather, compress, treat and process natural gas or fractionate NGLs cannot assure you that
future events, such as changes

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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 summary of the more significant existing environmental laws to which our business operations are subject and with which compliance may have a material adverse effect
on our capital expenditures, earnings or competitive position.

Air Emissions.Our operations are subject to the federal Clean Air Act, as amended and comparable state laws. These laws
regulate emissions of air pollutants from various industrial sources, including our processing and treatment plants, fractionation facilities and compressor stations, and also impose various
monitoring and reporting requirements. Such laws may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air
emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission
control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially
criminal enforcement actions. We will be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits
and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more
burdensome to us than to other similarly situated companies.

Hazardous Waste.Our operations generate wastes, including hazardous wastes that are subject to the federal Resource
Conservation and Recovery Act, as amended, or RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. While
RCRA currently excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas, these oil and
gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste
solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate wastes that are subject to RCRA or
comparable state law requirements.

Site Remediation.The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known
as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous
substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for
disposal of hazardous substances at offsite locations such as landfills. Although petroleum as well as natural gas is excluded from CERCLA's definition of "hazardous substance," in the course of our
ordinary operations we will generate wastes that may fall within the definition of a "hazardous substance." CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to
threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability
for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

We
currently own or lease, and in the past have owned or leased, properties that have been used for natural gas and NGL gathering, treating, processing, and fractionating activities for
many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been
released on or under the properties owned or leased by us, or on or under other locations where such substances have been taken for disposal. In addition, some of our properties have been operated by
third parties whose

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treatment
and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and
analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes or remediate contaminated property.

Water Discharges.Our operations are subject to the Federal Water Pollution Control Act, as amended, also known as the Clean
Water Act, and analogous state laws. These laws impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of
pollutants, including discharges resulting from a spill or leak incident, is prohibited by the U.S. Environmental Protection Agency, or EPA, or analogous state agencies. The Clean Water Act and
regulations implemented thereunder also prohibit discharges of dredged and fill
material into wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of pollutants from our pipelines or facilities could result in
administrative civil and criminal penalties as well as significant remedial obligations.

Global Warming and Climate Control.In response to recent studies suggesting that emissions of certain gases, referred to as
"greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere, the current session of the U.S. Congress is considering climate change-related
legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191,
would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a "cap and trade" scheme of regulation of
greenhouse gas emissionsa ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent
surrender of emission allowances that may be traded or acquired on the open market. Debate and a possible vote on this bill by the full Senate are anticipated to occur before mid-year
2008. In addition, at least one-third of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas
emissions resulting from our operations or from combustion of fuels (e.g., natural gas or NGLs) we produce.

Also,
as a result of the U.S. Supreme Court's decision on April 2, 2007 inMassachusetts, et al. v. EPA, and certain provisions of
the Clean Air Act, the EPA may regulate carbon dioxide and other greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases. The EPA has publicly stated its goal of issuing a proposed rule to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile
fuels but the timing for issuance of this proposed rule is unsettled as the agency reviews its mandates under the Energy Independence and Security Act of 2007, which includes expanding the use of
renewable fuels and raising the corporate average fuel economy standards. The Court's holding inMassachusettsthat greenhouse gases including carbon
dioxide fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under
certain CAA programs. New federal or state laws requiring adoption of a stringent greenhouse gas control program or imposing restrictions on emissions of carbon dioxide in areas of the United States
in which we conduct business could adversely affect our cost of doing business and demand for our services.

Pipeline Safety.Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the
Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation,
replacement and management of pipeline facilities. The NGPSA covers the pipeline

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transportation
of natural gas and other gases, and the transportation and storage of liquefied natural gas and requires any entity that owns or operates pipeline facilities to comply with the
regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our
natural gas pipeline operations are in substantial compliance with applicable NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing
laws and regulations, future compliance with the NGPSA could result in increased costs that, at this time, cannot reasonably be quantified.

The
DOT, through the Office of Pipeline Safety, adopted regulations to implement the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection,
Protection, Enforcement and Safety Act of 2006, which requires pipeline operators to, among other things, develop integrity management programs for gas transmission pipelines that, in the event of a
failure, could affect "high consequence areas." "High consequence areas" are defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where
people gather that are located along the route of a pipeline. States in which we operate have adopted similar regulations applicable to intrastate gathering and transmission lines. Our pipeline
systems are largely excluded from these regulations and are not generally situated within areas that would be designated "high consequence."Therefore, compliance with these regulations has not had a
significant impact on our operations.

Employee Health and Safety.We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and
comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous
materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.

Hydrogen Sulfide.Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans,
and exposure can result in death. The gas handled at our Worland gathering system contains high levels of hydrogen sulfide, and we employ numerous safety precautions at the system to ensure the safety
of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.

Anti-Terrorism Measures.The federal Department of Homeland Security Appropriations Act of 2007 required the
Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas
facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant
to the act and, on November 20, 2007, further issued an Appendix A to the interim rule that established chemicals of interest and their respective threshold quantities that will trigger
compliance with the interim rule. Facilities possessing greater than threshold levels of these chemicals of interest were required to prepare and submit to the DHS in January 2008 initial screening
surveys that the agency would use to determine whether the facilities presented a high level of security risk. Covered facilities that are determined by DHS to pose a high level of security risk will
be notified by DHS and will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding
inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. In January 2008, we prepared and submitted to the DHS initial screening surveys for certain
facilities operated by us that possess regulated chemicals of interest in excess of the Appendix A threshold levels. Because we are currently awaiting a response from DHS on the extent to which
some or all of our surveyed facilities may be determined to

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present
a high level of security risk, the associated costs for complying with this interim rule has not been determined by us, and it is possible that such costs ultimately could be substantial.

Title to Properties

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over
which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have
obtained, where necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county roads, municipal
streets, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were built was purchased in fee.

Some
of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights,
which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third party consents, permits and authorizations for the transfer of the assets necessary
for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations
will be obtained reasonably soon, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

We
lease the majority of the surface land on which our gathering systems operate. With respect to our Eagle Chief gathering system, we lease the surface land on which the Eagle Chief
processing plant, three of the four compressor stations, a produced water dumping station and the three pumping stations are located. With respect to our Bakken gathering system, we own the land on
which the processing plant is located and the land on which the compressor stations are located. In our Worland gathering system, we lease the surface land on which the Worland processing plant and
the compressor stations are located. With respect to our Badlands gathering system, we own the land on which the Badlands processing plant is located and we lease the land on which the four compressor
sites are located. We lease the surface lands on which our Matli processing plant and compressor station are located and we lease the surface lands on which most of our Kinta Area compressors are
located. At our Woodford Shale gathering system, we own the land on which one compressor station is located and lease the surface land on a second compressor station location.

We
believe that we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by our affiliates until we have made the appropriate filings
in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. Title to property may be subject to encumbrances. We believe that
none of these encumbrances will materially detract from the value of our properties or from our interest in these properties, nor will they materially interfere with their use in the operation of our
business.

We
believe that we either own in fee or have leases, easements, rights-of-way or licenses and have obtained the necessary consents, permits and franchise
ordinances to conduct our operations in all material respects.

Office Facilities

In addition to our pipelines and processing facility discussed above, we occupy approximately 12,358 square feet of space at our executive offices in Enid,
Oklahoma, under leases expiring through August 31, 2009. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our
needs for the immediate future and that additional facilities will be available on commercially reasonable terms as needed.

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Employees

We have no employees. Prior to September 25, 2006, employees of our general partner, Hiland Partners GP, LLC, provided services to us. In
connection with the initial public offering of Hiland Holdings, LP, all of the employees of our general partner became employees of the general partner of Hiland Holdings, LP, Hiland
Partners GP Holdings, LLC. As of December 31, 2007, Hiland Partners GP Holdings, LLC had 108 full-time employees who provide services to us. We are not a
party to any collective bargaining agreements, and we have not had any significant labor disputes in the past. We believe we have good relations with the employees of Hiland Partners GP
Holdings, LLC.

Address, Internet Web site and Availability of Public Filings

We maintain our principal corporate offices at 205 West Maple, Suite 1100, Enid, Oklahoma 73701. Our telephone number is (580) 242-6040.
Our Internet address is www.hilandpartners.com. We make the following information available free of charge on our Internet Web site:



We
make our SEC filings available on our Web site as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. The above
information is available in print to anyone who requests it.

Item 1A.    Risk Factors

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we
are subject are similar to those that would be faced by a corporation engaged in a similar business. The following risks could materially and adversely affect our business, financial condition or
results of operations. In that case, the amount of the distributions on our common units could be materially and adversely affected, the trading price of our common units could
decline.

Risks Related to Our Business

We may not have sufficient cash after the establishment of cash reserves and payment of our general partner's fees and expenses to enable us to pay
distributions at the current level.

We may not have sufficient available cash each quarter to pay distributions at the current level. Under the terms of our partnership agreement, we must pay our
general partner's fees and expenses and set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute on our units principally depends upon
the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:



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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:



A decrease in our cash flow will reduce the amount of cash we have available for distribution to our unitholders or to service our debt.

You should be aware that the amount of cash we have available for distribution or to service our debt 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 have cash available for distributions
or debt service during periods when we record losses and may not have cash available for distributions or debt service 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 or to
service our debt.

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. Natural gas prices have been high in recent years compared to historical periods. 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.

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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 or service our debt.

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) Atlas Pipeline Partners, Mustang Fuel Corporation and Duke Energy Field Services, LLC at our Eagle Chief gathering system, (2) Enogex, Inc. at our Matli
gathering system, (3) Bear Paw Energy, a subsidiary of ONEOK Partners, L.P., at our Badlands and Bakken gathering systems, (4) CenterPoint Energy Field Services at the Kinta Area
gathering system and (5) MarkWest Energy Partners and Enogex, Inc. at the Woodford Shale 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, 2007, CLR, Chesapeake Energy Corporation and Enerplus Resources (USA) Corporation supplied us with approximately 37%, 21%
and 12%, respectively, of our total natural gas volumes purchased. BP America Production Company and Chesapeake Energy Corporation supplied us with approximately 48% and 14%, respectively, of our
natural gas volumes gathered. 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.

If we do not make acquisitions on economically acceptable terms, our future growth may be limited.

Our ability to grow depends in part on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are
unable to make these accretive acquisitions 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 may be limited. Furthermore,
even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

Any
acquisition involves potential risks, including, among other things:



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If
we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial
and other relevant information that we will consider in determining the application of these funds and other resources.

Our
acquisition approach is based, in part, on our expectation of ongoing divestitures of midstream assets by large industry participants. A material decrease in such divestitures would
limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

Our ability to engage in construction projects and to make acquisitions will require access to a substantial amount of capital.

Our ability to engage in construction projects or to make acquisitions is dependent on obtaining adequate sources of outside financing, including commercial
borrowings and other debt and common unit issuances. While the initial funding of our acquisitions may consist of debt financing, our financial strategy is to finance acquisitions approximately
equally with equity and debt, and we would expect to repay such debt with proceeds of equity issuances to achieve this relatively balanced financing ratio. If we are unable to finance our growth
through external sources or are unable to achieve our targeted debt/equity ratios, or if the cost of such financing is higher than expected, we may be required to forgo certain construction projects
or acquisition opportunities or such construction projects or acquisition opportunities may not result in expected increases in distributable cash flow. Accordingly, our inability to obtain adequate
sources of financing on economically acceptable terms may limit our growth opportunities, which could have a negative impact on our cash available to pay distributions.

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 or to service our debt.

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 or to service our debt.

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 markets and prices for natural gas and NGLs depend upon factors beyond

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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:



We
operate under two types of contractual arrangements under which our total segment margin is exposed to increases and decreases in the price of natural gas and NGLs:
percentage-of-proceeds and percentage-of-index arrangements. Under percentage-of-proceeds arrangements, we generally purchase
natural gas from producers for an agreed percentage of proceeds or upon an index related price, and then sell the resulting residue gas and NGLs or NGL products at index related prices. Under
percentage-of-index arrangements, we purchase natural gas from producers at a fixed percentage of the index price for the natural gas they produce and subsequently sell the
residue gas and NGLs or NGL products at market prices. Under both of these types of contracts our revenues and total segment margin increase or decrease, whichever is applicable, as the price of
natural gas and NGLs fluctuates.

We may not successfully balance our purchases of natural gas and our sales of residue gas and NGLs, which increases our exposure to commodity price
risks.

We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised volumes or deliver in excess of contracted
volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will
face increased exposure to commodity price risks and could have increased volatility in our operating income.

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

One of the ways we may grow our business is through the construction of new midstream assets or the expansion of existing systems. 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

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production.
As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial
condition.

A change in the characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result
in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Our gathering facilities are exempt from FERC regulation under the NGA, but FERC jurisdiction still affects our business and the market for our products. FERC's
policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release, and market center
promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure
you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition,
the distinction between FERC-regulated transmission service and federally unregulated gathering services is the subject of regular litigation, so, in such a circumstance, the
classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts.

Other
state and local regulations also affect our business. Our gathering lines are subject to ratable take and common purchaser statutes in states in which we operate. Ratable take
statutes generally
require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to
purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport
natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. States in which we operate have adopted complaint based regulation of natural gas gathering activities,
which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. While our
proprietary gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge proprietary
status of a line, or the rates, terms and conditions of a gathering line providing transportation service.

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an
accidental release of hazardous substances into the environment.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of substances into the
environment and environmental protection. These laws and regulations require us to acquire permits to conduct regulated activities, to incur capital expenditures to limit or prevent releases of
substances from our facilities, and to respond to liabilities for pollution resulting from our operations. Governmental authorities enforce compliance with these laws and regulations and the permits
issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws 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 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 into the environment.

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There
is inherent risk of incurring significant environmental costs and liabilities in our business due to our handling of natural gas, NGLs and wastes, the release of water discharges
or air emissions related to our operations, and historical industry operations and waste disposal practices conducted by us or predecessors operators. 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 some or any of these costs from
insurance.

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, our cash flows could be adversely affected.

If we fail to renew any of our significant contracts as they expire under the terms of the particular agreement, our revenues and cash flow may be
adversely affected and our ability to make distributions to our unitholders or service our debt may be reduced.

If we fail to renew any of our significant natural gas sales contracts, NGL sales arrangements, hedging contracts, natural gas purchase and gathering contracts or
our compression services agreement as they expire under the terms of the particular agreement, we would be adversely affected unless we were able to replace such contract with a contract containing
similar terms. For example, our compression services agreement with CLR has an initial term ending January 28, 2009 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. If CLR elects to terminate the agreement and we fail to renew the agreement
with CLR, we would be adversely affected unless we were able to provide air and water compression services to other parties in the area where our air and compression facilities are located.

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:



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These
risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental
damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our
operations. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we do not have any property insurance on any of our underground pipeline
systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. In addition, we do
not have business interruption insurance. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.

Restrictions in our credit facility limit our ability to make distributions to you and may limit our ability to capitalize on acquisitions and other
business opportunities.

Our credit facility contains various covenants limiting our ability to incur indebtedness, grant liens, engage in transactions with affiliates, make distributions
to our unitholders and capitalize on acquisition or other business opportunities. It also contains covenants requiring us to maintain certain financial
ratios and tests. We are prohibited from making any distribution to unitholders if such distribution would cause a default or an event of default under our credit facility. Any subsequent refinancing
of our current indebtedness or any new indebtedness could have similar or greater restrictions. At December 31, 2007, our outstanding long-term indebtedness was approximately
$221.1 million under our senior secured revolving credit facility. Payments of principal and interest on the indebtedness will reduce the cash available for distribution on our units.

Due to our lack of asset diversification, adverse developments in our midstream operations would reduce our ability to make distributions to our
unitholders or to service our debt.

We rely exclusively on the revenues generated from our gathering, dehydration, treating, processing, fractionation and compression services businesses, and as a
result, our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Due to our lack of diversification in asset type, an adverse development in one of these
businesses would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, reduce debt or
finance internal growth projects.

If the overall economy strengthens, it is possible that monetary policy will tighten further, resulting in higher interest rates to counter possible inflation.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our
unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities
for investment decision making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising
interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or finance internal growth projects.

Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.

We utilize derivative financial instruments related to the future price of natural gas and to the future price of NGLs with the intent of reducing volatility in
our cash flows due to fluctuations in

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commodity
prices. While our hedging activities are designed to reduce commodity price risk, we remain exposed to fluctuations in commodity prices to some extent.

The
extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on
posted market prices, which may differ significantly from the actual natural gas prices or NGLs prices that we realize in our operations. Furthermore, our hedges relate to only a portion of the volume
of our expected sales and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future sales may be significantly higher or lower than we estimate
at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount
is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow
from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

As
a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase
the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms
of the derivative instruments are imperfect, and our hedging procedures may not be properly followed. We cannot assure you that the steps we take to monitor our derivative financial instruments will
detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or
other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks,
on the energy transportation industry in general, and on us in particular, is not known at this time. Increased security measures taken by us as a precaution against possible terrorist attacks have
resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns
may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for refined products, and the possibility that infrastructure facilities could be direct
targets of, or indirect casualties of, an act of terror.

Changes
in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to
us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

Risks Inherent in an Investment in Us

Harold Hamm and his affiliates control our general partner, which has sole responsibility for conducting our business and managing our operations.
Affiliates of Harold Hamm and our general partner have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

Harold Hamm and his affiliates control Hiland Partners GP Holdings, LLC, the general partner of Hiland Holdings, a publicly traded Delaware limited
partnership that directly or indirectly owns 100% of our general partner. As a result, Harold Hamm and his affiliates control our general partner, which has sole responsibility for conducting our
business and managing our operations. Conflicts of interest may arise between Harold Hamm and his affiliates, including our general partner, on the one hand, and us and our unitholders, on the other
hand. As a result of these conflicts, the general partner may

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favor
its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:



Unitholders have limited voting rights and limited ability to influence our operations and activities.

Unitholders have only limited voting rights on matters affecting our operations and activities and, therefore, limited ability to influence management's decisions
regarding our business. Unitholders did not select our general partner or elect the board of directors of our general partner and effectively have no right to select our general partner or elect its
board of directors in the future.

Unitholders'
voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then
outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be
voted on any matter. In addition, the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other
provisions limiting the unitholders' ability to influence the manner or direction of management.

Our general partner determines the cost reimbursement and fees payable to it from us; such payments may be substantial and could reduce our cash
available for distribution to you.

Prior to making any distributions on our common units, we will reimburse our general partner for expenses it incurs on our behalf. Payments to our general partner
may be substantial and will reduce the amount of available cash for distribution to unitholders. We will reimburse our general partner for the provision by it and its affiliates of various general and
administrative services for our benefit, including the salaries and costs of employee benefits for employees of the general partner and its affiliates that provide services to us. Our general partner
determines the amount of expenses allocable to us. There is no cap on the amount that may be paid or reimbursed to our general partner for compensation or expenses incurred on our behalf. Our general
partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner.

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Our partnership agreement limits our general partner's fiduciary duties to our unitholders and restricts the remedies available to unitholders for
actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For
example, our partnership agreement:



In
order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions
discussed above.

Harold Hamm and CLR may engage in limited competition with us.

Harold Hamm and CLR and their affiliates may engage in limited competition with us. Pursuant to the omnibus agreement entered into in connection with our initial
public offering, Harold Hamm has agreed that neither he nor any of his affiliates (including CLR) will engage in, whether by acquisition, construction, investment in debt or equity interests of any
person or otherwise, the business of gathering, treating, processing and transportation of natural gas in North America, the transportation and fractionation of NGLs in North America, and
constructing, buying or selling any assets related to the foregoing businesses. This restriction does not apply to:



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These
non-competition obligations will terminate on the first to occur of the following events:



In
addition, in connection with the initial public offering of Hiland Holdings, Hiland Holdings and its general partner entered into a non-competition agreement with us
pursuant to which Hiland Holdings and its general partner have agreed that they will not, and they will cause any person or entity controlled by Hiland Holdings or its general partner (other than our
general partner, our subsidiaries and us) 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. The non-competition agreement has the same permitted exceptions as the omnibus agreement and will terminate on the first day on which neither Hiland Holdings nor its
general partner control us.

Even if unitholders are dissatisfied, they cannot remove our general partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability
to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general
partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner.
Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they would have little ability to remove our general partner. As a result of these limitations, the price
at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The
unitholders are unable initially to remove the general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent removal.
The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. As of March 7, 2008, affiliates
of the general partner owned 57.7% of the limited partner units outstanding. Also, if the general partner is removed without cause during the subordination period and units held by the general partner
and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be
extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the
subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has
entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner.
Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder's dissatisfaction with the

34

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general
partner's performance in managing our partnership would most likely result in the termination of the subordination period.

Furthermore,
unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of
units then outstanding, other than the general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of the general
partner's general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the
consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our
general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors of our general partner with their own choices and to control the
decisions taken by the board of directors.

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our
business and affairs.

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and
affairs. We can provide no assurance that the general partner will continue to provide us the officers and employees that are necessary for the conduct of our business nor that such provision will be
on terms that are acceptable to us. Other than option agreements, neither we nor our general partner have entered into any employment agreements with any officers of our general partner. If the
general partner fails to provide us with adequate personnel, our operations could be adversely impacted. In addition, certain of the officers of our general partner, including the chief executive
officer and chief financial officer, may also serve as officers and directors of affiliates of the general partner.

We may issue additional common units without your approval, which would dilute your existing ownership interests.

During the subordination period, our general partner, without the approval of our unitholders, may cause us to issue up to 1,360,000 additional common units. Our
general partner may also cause us to issue an unlimited number of additional common units or other equity securities of equal rank with the common units, without unitholder approval, in a number of
circumstances such as:



35

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In
addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

The
issuance of additional common units or other equity securities of equal or senior rank will have the following effects:



After
the end of the subordination period, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement
does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time.

Our general partner's discretion in determining the level of cash reserves may reduce the amount of available cash for distribution to you.

Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it determines are necessary to fund our future
operating expenditures. In addition, our partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply
with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution to you.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our
general partner or its affiliates.

In some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions. These borrowings are permitted even if
the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions, or to hasten the expiration of the subordination period.

All of the membership interests in our general partner and all of the common and subordinated units in us that are owned by Hiland Holdings are pledged
as security under Hiland Holdings' credit facility. Upon an event of default under Hiland Holdings' credit facility, a change in ownership or control of us could ultimately result.

The 100% membership interest in our general partner and the 1,301,471 common units and 4,080,000 subordinated units in us that are owned by Hiland Holdings are
pledged under Hiland Holdings' credit facility. Hiland Holdings' credit facility contains customary and other events of default. Upon an event of default, the lenders under Hiland Holdings' credit
facility could foreclose on Hiland

36

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Holdings'
assets, which could ultimately result in a change in control of our general partner and a change in the ownership of our units held by Hiland Holdings.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation,
which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current
market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a
sale of your units. As of March 7, 2008, affiliates of our general partner owned approximately 24.9% of the common units and, at the end of the subordination period, assuming no additional
issuances of common units, affiliates of our general partner will own approximately 57.7% of the common units.

You could be liable for any and all of our obligations if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the
partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the
liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be
liable for any and all of our obligations as if you were a general partner if:



Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the
Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides
that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware
law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are
known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to
partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by
individual states. If we were to be treated as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, taxes
paid, if any, would reduce the amount of cash available for distribution to you.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal
income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite
the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal
income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a
corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If
we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%,
and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to
you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a
material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current
law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of
widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other
forms of taxation. For example, we will be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year that ends December 31, 2007.
Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will
reduce the cash available for distribution to you.

Our
partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us
to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that
law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or
administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by
administrative, legislative or judicial interpretation at any time. For example, members of Congress recently began considering substantive changes to the existing U.S. federal income tax laws that
affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently
proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such
changes could negatively impact the value of an investment in our common units.

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If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest
will reduce our cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The
IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not
agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs
of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you
will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not
receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units.
Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to
the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original
cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture.
In addition, because the amount realized includes a unitholder's share of nonrecourse liabilities if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from
the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax
consequences to them.

Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and
non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement
plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest
effective applicable tax rate, and such non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a
tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this
treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may
not conform to all aspects

39

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of
existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax
benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of
our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, and, if successful, we would be
required to change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common
units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury
Regulations. If the Internal Revenue Service, or IRS, were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he
would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, he may no
longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of
gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies that could result in a shift of income, gain, loss and deduction between the general partner and the
unitholders. The IRS may successfully challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or
loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a
shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible
assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss
and deduction between the general partner and certain of our unitholders.

A
successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount
of gain from our unitholders' sale of common units and could have a negative impact on the value of the common

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units
or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our
partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and
profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our
unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In
the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable
income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but
instead, we would be treated as a
new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our
common units.

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be
required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to
comply with those requirements. We currently do business or own property in various states, most of which impose a tax on individuals, corporations and other entities. As we make acquisitions or
expand our business, we may own assets or conduct business in additional states that impose similar income taxes. It is your responsibility to file all United States federal, foreign, state and local
tax returns.

Item 1B.    Unresolved Staff Comments

None.

Item 3.    Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a
party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental
protection statutes to which we are subject. We maintain insurance policies with insurers in amounts and with coverage and deductibles as our general partner believes are reasonable and prudent.
However, we cannot assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of
insurance will be available in the future at economical prices.

Item 4.    Submission of Matters to a Vote of Security Holders

None.

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PART II

Item 5.    Market for Registrant's Common Units and Related Unitholder Matters and Issuer Purchases of Equity Securities

Our limited partner common units began trading on the Nasdaq National Market under the symbol "HLND" commencing with our initial public offering on
February 10, 2005 at an initial public offering price of $22.50 per common unit. As of March 7, 2008, the market price for the common units was $47.00 per unit and there were
approximately 3,900 common unitholders, including beneficial owners of common units held in street name, and one record holder of our subordinated units. There is no established public trading market
for our subordinated units. We 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 exists, under our credit facility. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital
ResourcesDescription of IndebtednessCredit Facility."

The
following table shows the high and low prices per common unit, as reported by the NASDAQ National Market, for the periods indicated. Cash distributions shown were paid within
45 days after the end of each quarter.

Common Unit Price RangesCash Distribution Paid Per Unit(a)High

LowYear Ended December 31, 2007Quarter Ended December 31

$
53.00

$
41.60

$
0.7950Quarter Ended September 30

$
60.50

$
46.02

$
0.7550Quarter Ended June 30

$
61.75

$
52.05

$
0.7325Quarter Ended March 31

$
58.49

$
52.54

$
0.7125Year Ended December 31, 2006Quarter Ended December 31

$
56.86

$
44.00

$
0.7125Quarter Ended September 30

$
47.33

$
42.00

$
0.7000Quarter Ended June 30

$
46.58

$
41.21

$
0.6750Quarter Ended March 31

$
43.95

$
36.84

$
0.6500




Cash Distribution Policy

Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to unitholders of
record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner to
provide for the proper conduct of our business, to comply with applicable law, any of our debt instruments, or other agreements, or to provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters. 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.

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Upon
the closing of our initial public offering, affiliates of Harold Hamm, the Hamm Trusts and an affiliate of Randy Moeder, our past Chief Executive Officer, received an aggregate of
4,080,000 subordinated units. The subordinated units were contributed to Hiland Holdings GP, LP, a publicly owned limited partnership on the date of its initial public offering,
September 25, 2006. 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 the specified target
levels shown below:

|                               |  |                            |  | Marginal Percentage
Interest in Distributions |  
|------------------------------ |  | -------------------------- |  | --------------------------------------------- | -
|
|
|
|Minimum Quarterly Distribution |  | $0.45                      |  | 98                                            | %
|First Target Distribution      |  | Up to $0.495               |  | 98                                            | %
|Second Target Distribution     |  | Above $0.495 up to $0.5625 |  | 85                                            | %
|Third Target Distribution      |  | Above $0.5625 up to $0.675 |  | 75                                            | %
|Thereafter                     |  | Above $0.675               |  | 50                                            | %

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The
equity compensation plan information required by Item 201(d) of Regulation S-K in response to this item is incorporated by reference from Note 1 of
the notes to the consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

Issuer Purchases of Equity Securities

We did not repurchase any of our common units during the fourth quarter of fiscal 2007.

Item 6.    Selected Historical Financial and Operating Data

The following table sets forth selected historical financial and operating data of Hiland Partners, LP and our predecessor, Continental Gas, Inc.
("CGI") as of and for the periods indicated. The selected historical financial data as of, and for the years ended December 31, 2007, 2006 and 2005 are derived from the audited financial
statements of Hiland Partners, LP. The selected historical financial data for the years ended December 31, 2004 and 2003 are derived from the audited financial statements of CGI.

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 plus interest expense, provision for income taxes and depreciation, amortization and accretion expense. We define midstream segment margin as
midstream revenue less midstream purchases. Midstream purchases include the following costs and expenses: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas and NGLs
purchased by us from affiliates, and costs of crude oil purchased by us from third parties. We define compression segment margin as the lease payments received under our compression facilities lease
agreement with CLR 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." For a reconciliation of
these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please refer to the reconciliation following the
table below.

Maintenance
capital expenditures represent capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to
extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures
made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our
operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses
exceeds cost reductions typically resulting from routine maintenance. We treat costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life
of existing assets as operations and maintenance expenses as we incur them.

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The
following table sets forth our selected historical financial data, which has been derived from our audited historical financial statements. The table should be read together with
"Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

|                                                                |  | Hiland Partners, LP |         | Predecessor Continental Gas, Inc. |  
|--------------------------------------------------------------- |  | ------------------- | ------- | --------------------------------- | -
|
|
|
|Summary of Operations Data:                                     |  |                     |         |                                   |  
|Total revenues                                                  |  | $                   | 278,043 |                                   | $
|Operating costs and expenses:                                   |  |                     |         |                                   |  
|Midstream purchases (exclusive of items shown separately below) |  |                     | 195,212 |                                   |  
|Operations and maintenance                                      |  |                     | 23,279  |                                   |  
|Depreciation, amortization and accretion                        |  |                     | 29,855  |                                   |  
|Property impairment expense                                     |  |                     |        |                                   |  
|(Gain) loss on asset sales                                      |  |                     |        |                                   |  
|General and administrative                                      |  |                     | 7,587   |                                   |  
|                                                                |  |                     |         |                                   |  
|Total operating costs and expenses                              |  |                     | 255,933 |                                   |  
|                                                                |  |                     |         |                                   |  
|Operating income                                                |  |                     | 22,110  |                                   |  
|Other income (expense):                                         |  |                     |         |                                   |  
|Interest expense                                                |  |                     | (11,346 | )                                 |  
|Amortization of deferred loan costs                             |  |                     | (410    | )                                 |  
|Interest income and other                                       |  |                     | 430     |                                   |  
|                                                                |  |                     |         |                                   |  
|Total other income (expense)                                    |  |                     | (11,326 | )                                 |  
|                                                                |  |                     |         |                                   |  
|Income (loss) from continuing operations                        |  |                     | 10,784  |                                   |  
|Discontinued operations, net                                    |  |                     |        |                                   |  
|                                                                |  |                     |         |                                   |  
|Income (loss) before change in accounting principle             |  |                     | 10,784  |                                   |  
|Cumulatve effect of change in accounting principle              |  |                     |        |                                   |  
|                                                                |  |                     |         |                                   |  
|Net income                                                      |  | $                   | 10,784  |                                   | $
|                                                                |  |                     |         |                                   |  
|Less income attributable to predecessor                         |  |                     |        |                                   |  
|Less general partner interest in net income                     |  |                     | 4,526   |                                   |  
|                                                                |  |                     |         |                                   |  
|Limited partners' interest in net income                        |  | $                   | 6,258   |                                   | $
|                                                                |  |                     |         |                                   |  
|Net income per limited partner unitbasic(1)                    |  | $                   | 0.67    |                                   | $
|                                                                |  |                     |         |                                   |  
|Net income per limited partner unitdiluted(1)                  |  | $                   | 0.67    |                                   | $
|                                                                |  |                     |         |                                   |  
|Cash distributions per limited partner unit(2)                  |  | $                   | 3.00    |                                   | $
|                                                                |  |                     |         |                                   |  
|Balance Sheet Data (at end of period):                          |  |                     |         |                                   |  
|Property and equipment, at cost, net                            |  | $                   | 319,320 |                                   | $
|Total assets                                                    |  |                     | 410,473 |                                   |  
|Accounts payableaffiliates                                     |  |                     | 7,880   |                                   |  
|Long-term debt, net of current maturities                       |  |                     | 226,104 |                                   |  
|Net equity                                                      |  |                     | 139,167 |                                   |  

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|Cash Flow Data:                              |  |   |         |   |   |          |   |   |         |   |   |        |   |   |         |  
|-------------------------------------------- |  | - | ------- | - | - | -------- | - | - | ------- | - | - | ------ | - | - | ------- | -
|Net cash flow provided by (used in):         |  |   |         |   |   |          |   |   |         |   |   |        |   |   |         |  
|Operating activities                         |  | $ | 40,702  |   | $ | 39,580   |   | $ | 8,122   |   | $ | 7,957  |   | $ | 4,464   |  
|Investing activities                         |  |   | (83,408 | ) |   | (158,426 | ) |   | (74,888 | ) |   | (5,290 | ) |   | (17,286 | )
|Financing activities                         |  |   | 42,817  |   |   | 123,045  |   |   | 72,736  |   |   | (2,946 | ) |   | 13,212  |  
|Other Financial Data:                        |  |   |         |   |   |          |   |   |         |   |   |        |   |   |         |  
|Midstream segment margin                     |  | $ | 78,012  |   | $ | 58,674   |   | $ | 29,295  |   | $ | 15,764 |   | $ | 9,016   |  
|Compression segment margin                   |  |   | 4,819   |   |   | 4,819    |   |   | 4,217   |   |   |       |   |   |        |  
|                                             |  |   |         |   |   |          |   |   |         |   |  
|Total segment margin                         |  | $ | 82,831  |   | $ | 63,493   |   | $ | 33,512  |   | $ | 15,764 |   | $ | 9,016   |  
|                                             |  |   |         |   |   |          |   |   |         |   |  
|EBITDA(3)                                    |  | $ | 52,395  |   | $ | 42,751   |   | $ | 23,875  |   | $ | 9,843  |   | $ | 4,773   |  
|                                             |  |   |         |   |   |          |   |   |         |   |  
|Non cash realized (gain) loss on derivatives |  | $ | (373    | ) | $ | (113     | ) | $ |        |   | $ |       |   | $ |        |  
|Non cash unit based compensation expense     |  | $ | 951     |   | $ | 473      |   | $ |        |   | $ |       |   | $ |        |  
|Maintenance capital expenditures             |  | $ | 3,423   |   | $ | 3,434    |   | $ | 2,225   |   | $ | 1,693  |   | $ | 1,769   |  
|Expansion capital expenditures               |  |   | 87,530  |   |   | 155,103  |   |   | 72,723  |   |   | 3,474  |   |   | 14,900  |  
|Discontinued operations                      |  |   |        |   |   |         |   |   |        |   |   | 159    |   |   | 745     |  
|                                             |  |   |         |   |   |          |   |   |         |   |  
|Total capital expenditures                   |  | $ | 90,953  |   | $ | 158,537  |   | $ | 74,948  |   | $ | 5,326  |   | $ | 17,414  |  
|                                             |  |   |         |   |   |          |   |   |         |   |  
|Operating Data:                              |  |   |         |   |   |          |   |   |         |   |   |        |   |   |         |  
|Inlet natural gas (MCF/d)(4)                 |  |   | 215,551 |   |   | 157,556  |   |   | 57,545  |   |   | 50,283 |   |   | 47,633  |  
|Natural gas sales (MMBTU/d)                  |  |   | 80,731  |   |   | 66,947   |   |   | 47,096  |   |   | 40,560 |   |   | 37,701  |  
|NGL sales (Bbls/d)                           |  |   | 4,696   |   |   | 3,347    |   |   | 1,965   |   |   | 1,133  |   |   | 895     |  
|Natural gas gathered (MMBtu/d)               |  |   | 123,008 |   |   | 85,540   |   |   |        |   |   |       |   |   |        |  

---

Reconciliation of Non-GAAP Financial Measures

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

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of
midstream segment margin and compression segment margin) to operating income, in each case, on a historical basis for each of the periods indicated.

|                                          |                          | Hiland Partners, LP |        | Predecessor Continental Gas, Inc. |  
|----------------------------------------- | ------------------------ | ------------------- | ------ | --------------------------------- | -
|
|
|
|Reconciliation of EBITDA to Net Income:   |                          |                     |        |                                   |  
|Net income                                |                          | $                   | 10,784 |                                   | $
|Add:                                      |                          |                     |        |                                   |  
|Depreciation, amortization and accretion  |                          |                     | 29,855 |                                   |  
|Amortization of deferred loan costs       |                          |                     | 410    |                                   |  
|Interest expense                          |                          |                     | 11,346 |                                   |  
|                                          |                          |                     |        |                                   |  
|EBITDA(1)                                 |                          | $                   | 52,395 |                                   | $
|                                          |                          |                     |        |                                   |  
|Reconciliation of Total Segment Margin to |                          |                     |        |                                   |  
|                                          | Operating Income (Loss): |                     |        |                                   |  
|Operating income (loss)                   |                          | $                   | 22,110 |                                   | $
|Add:                                      |                          |                     |        |                                   |  
|Operations and maintenance expenses       |                          |                     | 23,279 |                                   |  
|Depreciation, amortization and accretion  |                          |                     | 29,855 |                                   |  
|Property impairment expense               |                          |                     |       |                                   |  
|(Gain) loss on asset sales                |                          |                     |       |                                   |  
|General and administrative expenses       |                          |                     | 7,587  |                                   |  
|                                          |                          |                     |        |                                   |  
|Total segment margin                      |                          | $                   | 82,831 |                                   | $
|                                          |                          |                     |        |                                   |  

---

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion in conjunction with our Consolidated Financial Statements and notes thereto included elsewhere in this report.

Overview

We are a Delaware limited partnership formed in October 2004 to own and operate the assets that have historically been owned and operated by CGI and Hiland
Partners, LLC.

CGI
historically owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland and Bakken gathering systems and the Kinta Area gathering
systems we acquired on May 1, 2006. Hiland Partners, LLC historically has owned our Worland gathering system, our compression services assets and the Bakken gathering system. CGI is our
predecessor for accounting purposes. As a result, our historical financial statements for periods prior to February 15, 2005, the date of our initial public offering, are the financial
statements of CGI.

In
connection with our initial public offering, the former owners of CGI and Hiland Partners, LLC and certain of our affiliates, including our general partner, contributed to us,
all of the assets and operations of CGI, 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.

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We completed our initial public offering of 2,300,000 common units on February 15, 2005, receiving net proceeds of $48.1 million. The proceeds from the public offering were
used to (1) pay remaining offering costs of $2.2 million and deferred debt issuance costs of $0.6 million, (2) pay outstanding indebtedness of $22.9 million,
(3) redeem $6.3 million of common units from an affiliate of Harold Hamm and the Hamm Trusts, and (4) make a $3.9 million distribution to the previous owners of Hiland
Partners, LLC. We retained $12.2 million of the net proceeds to replenish working capital.

Effective
September 1, 2005, we consummated the Bakken acquisition pursuant to which we acquired the outstanding membership interests in Hiland Partners, LLC, an Oklahoma
limited liability company, for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. Hiland
Partners, LLC's principal asset is the Bakken gathering system located in eastern Montana.

We
completed a follow-on offering of 1,630,000 common units on November 21, 2005, receiving net proceeds of $66.1 million including our general partner's
contribution of $1.4 million. We used $65.2 million of the proceeds from the public offering to repay a portion of our credit facility borrowings that we had previously used to fund the
Bakken acquisition.

On
May 1, 2006, we acquired the Kinta Area gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for
$96.4 million. We financed this acquisition with $61.2 million of borrowings from our credit facility and $35.0 million of proceeds from the issuance of 761,714 common units at
$45.03 per unit to Hiland Partners GP, LLC, our general partner, and from its 2% general partner contribution.

On
September 25, 2006, certain affiliated unitholders contributed (i) all of the membership interests in our general partner, which owns the 2% general partner interest and
all of the incentive distribution rights in us and (ii) 1,301,471 common units (including 761,714 common units held by our general partner) and 4,080,000 subordinated units in us to Hiland
Holdings GP, LP, a publicly owned limited partnership (NASDAQ: HPGP), in exchange for 13,550,000 limited partner units, representing a 62.7% ownership in Hiland
Holdings GP, LP. Hiland Partners GP Holdings, LLC, a Delaware limited liability company formed on May 10, 2006, is the general partner of Hiland
Holdings GP, LP.

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:



Our
midstream assets consist of 14 natural gas gathering systems with approximately 2,024 miles of gas gathering pipelines, five natural gas processing plants, seven natural gas treating
facilities and three

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NGL
fractionation facilities. Our compression assets consist of two air compression facilities and a water injection plant.

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 midstream revenue minus midstream purchases. Midstream revenue includes revenue from the sale of natural
gas, NGLs and NGL products resulting from our gathering, treating, processing and fractionation activities and fixed fees associated with the gathering of natural gas and the transportation and
disposal of saltwater. Midstream purchases include the cost of natural gas, condensate and NGLs purchased by us from third parties and the cost for the transportation and fractionation of NGLs by
third parties. Our midstream segment margin is impacted by our midstream contract portfolio, which is described in more detail below.

With
respect to our compression segment, following the restructuring of our lease arrangement to become a service arrangement in connection with our initial public offering as described
in "Items Impacting Comparability of Our Financial Results," our compression segment margin equals the fee we earn under our Compression Services Agreement with CLR for providing air
compression and water injection services. The fee that we earn under this agreement is fixed so long as our facilities meet specified availability requirements, regardless of CLR's utilization. As a
result, our compression segment margin is dependent on our ability to meet their utilization levels. For a discussion of this agreement, please read "Our ContractsCompression
Services Agreement."

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Total
segment margin is a Non-GAAP performance measure. For a reconciliation of Total Segment Margin to the most comparable GAAP financial measure, please see "Item 6.
Selected Historical Financial and Operating Data."

Operations and Maintenance Expenses.Operations and maintenance expenses are costs associated with the operation of a
specific asset. Direct labor, insurance, ad valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operations and maintenance expenses.
These expenses remain relatively stable independent of the volumes through our systems but fluctuate slightly depending on the activities performed during a specific period.

General and Administrative Expenses.Our general and administrative expenses include the cost of employee and officer
compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations.

Our
general and administrative expenses have increased as a result of our becoming a public company, combined with an increased need for corporate office employees as a result of
acquisitions and internal growth. These expenses were approximately $7.6 million for 2007, $5.0 million for 2006 and $2.5 million for 2005. These increases were primarily due to
increased wages and benefits as a result of growth, non-cash compensation expense related to option, restricted unit and phantom unit awards, acquisition evaluation costs, costs of tax
return preparations, filing annual and quarterly reports with the Securities and Exchange Commission, investor relations, directors' and officers' insurance and registrar and transfer agent fees.

In
the omnibus agreement we entered into with CLR in connection with our initial public offering on February 15, 2005, CLR agreed to provide technology support and human resource
functions to us for two years, at the lower of CLR's cost to provide the services or $50,000 per year. During the third quarter of 2006, we hired a director of information technology and a director of
human resources and transitioned these services away from CLR.

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:



EBITDA
is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders and is used as a gauge for compliance with some of our financial covenants
under our credit facility. EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented
in accordance with GAAP. For a reconciliation of EBITDA to the most comparable GAAP financial measure, please see "Item 6. Selected Historical Financial and Operating Data."

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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. We receive daily summaries of new drilling permits and completion reports filed with the state regulatory agencies that govern these activities
on all of our gathering systems. Producers that have dedicated acreage to our Bakken gathering system provide us with their projected annual drilling schedules, which are updated periodically.
Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel at our
corporate offices. These 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 and where market conditions permit, 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. 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 one forward sales contract to sell
1,200,000 MMBtu of natural gas at $8.43 per MMBtu on our Eagle Chief, Matli and Kinta Area gathering systems.

We
also use cash flow hedges to limit our exposure to changing natural gas prices. Under these hedges we settle monthly on the difference between the sales or purchases of future
production to or from our counterparty at fixed prices and the price that will be established on the date of hedge

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settlement
by reference to a specified index price. These hedge contracts currently cover periods of up to twenty-four months from the date of the hedge.

Our NGL Sales Arrangements

We sell NGLs and NGL products at the tailgate of our facilities to ONEOK Hydrocarbon, LP, SemStream, L.P., and a subsidiary of Kinder Morgan Energy
Partners, L.P. We typically sell NGLs and NGL products on a monthly basis under index related pricing terms in our mid-continent region and at market prices in our rocky mountain
region. We also use cash flow hedges to limit our exposure to changing NGL prices. Under these hedges we settle monthly on the difference between the sales of future production to our counterparty at
a fixed price and the price that will be established on the date of hedge settlement by reference to a specified index price. These hedges currently cover periods of up to twelve months from the date
of the hedge.

Hedging Contracts

To insure that our hedging financial instruments will be used solely for hedging commodity price risks and not for speculative purposes, we continually review our
hedges for compliance with our hedging policies and procedures. We recognize gains and losses from the settlement of our hedges in revenue when we either sell or buy the associated physical residue
natural gas or sell the associated physical natural gas liquid. Any gain or loss realized as a result of hedging is substantially offset in the market when we either sell or buy the physical residue
natural gas or sell the physical natural gas liquid. All of our hedges are characterized as cash flow hedges as defined in Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. We determine gains or losses on open and closed hedging transactions based upon the difference between the hedge price and the physical
price. For a more detailed discussion on our hedging activity, please read commodity price risks included in Item 7A "Quantitative and Qualitative Disclosures about Market Risk."

Our Natural Gas Purchase and Gathering Contracts

With respect to our natural gas gathering, compression, dehydrating, treating, processing and marketing activities and our NGL fractionation activities, we
contract under four types of arrangements. Under all contracts except the fixed-fee gathering arrangement, 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. Under the
fixed-fee gathering arrangement, we do not purchase or take title to the gas supplied to us.

The
following is a summary of the four types of natural gas purchase contracts that accounted for the largest percentage of volumes purchased for the years ended December 31,
2007, 2006 and 2005.



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Compression Services Agreement

Under the compression services agreement that we entered into with CLR in connection with our initial public offering and effective as of January 28, 2005,
CLR 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, CLR 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 CLR'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. CLR 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 CLR's failure to supply power or water or a force majeure. The agreement has an initial term ending
January 28, 2009 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

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infrastructure,
personnel and producer and customer relationships to provide an integrated package of services. We may also pursue selected acquisitions in new geographic areas to the extent they
present growth opportunities similar to those we are pursuing in our existing areas of operations. To successfully execute our growth strategy, we will require access to capital on competitive terms.
We intend to finance future acquisitions primarily by using the capacity available under our bank credit facility and equity or debt offerings or a combination of both.

Capital Expenditures.We make capital expenditures either to maintain our assets or the 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 CGI and Hiland Partners, LLC. As part of our
formation, immediately prior to consummation of our initial public offering, the former owners of CGI and Hiland Partners, LLC contributed to us all of the assets and operations of CGI other
than a portion of its working capital assets and all of the assets and operations of Hiland Partners, LLC, other than a portion of its working capital assets and the assets related to the
Bakken gathering system. Effective September 1, 2005, we acquired Hiland Partners, LLC, which owns the Bakken gathering system.

CGI
is our predecessor for accounting purposes and has historically owned all of our natural gas gathering, processing and fractionation assets other than the Worland and Bakken
gathering systems and the Kinta Area gathering systems we acquired on May 1, 2006. As a result, our historical financial statements for the periods prior to February 15, 2005 are the
financial statements of CGI.

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.

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Restructuring of Compression Facilities Lease

Prior to our initial public offering, Hiland Partners, LLC owned our Horse Creek air compression facility and our Cedar Hills water injection facility. In
2002, Hiland Partners, LLC entered into a five year lease agreement with CLR, pursuant to which Hiland Partners, LLC leased the facilities to CLR. CLR 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 CLR, 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 CLR for a fee. As part of the restructuring, the personnel at CLR that operated the facilities were transferred to us. Under the new services agreement, we receive a fixed
payment of approximately $4.8 million per year as compared to $3.8 million per year under the prior lease agreement. In connection with the new services arrangement, we incur
approximately $1.0 million per year in additional operating costs. For a description of the restructured agreement, please read "Our ContractsCompression Services
Agreement."

Construction and Acquisition Activities

Since our inception, we have grown through a combination of building gas gathering and processing assets and acquisitions. For example, we commenced operation of
the Matli gathering system in 1999, constructed the original Matli processing plant in 2003 and completed the construction of a new processing plant in 2006. Additionally, we acquired the Worland
gathering system in 2000 and the Carmen gathering system in 2003. We acquired the Carmen gathering system in 2003 as an expansion of our Eagle Chief gathering system. Prior to our acquisition of the
Carmen gathering system, we purchased the gas from the previous owner, processed it and returned it to the previous owner pursuant to a keep-whole arrangement. After we acquired the Carmen
gathering system, we terminated this keep-whole arrangement and now sell the gas at the tailgate of the Eagle Chief processing plant. In addition, we completed the Bakken acquisition in
September 2005. These 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.

We
acquired the Kinta Area gathering assets in May 2006 and operate the gathering assets substantially differently than were operated by the previous owner. Since there was no sufficient
continuity of the Kinta Area gathering assets' operations prior to and after our acquisition, disclosure of prior financial information would not be material to an understanding of future operations.
Therefore, the acquisition has been recorded as a purchase of assets and not of a business.

We
expanded our processing plant and our existing field-gathering infrastructure and constructed a 40,000 Mcf/d nitrogen rejection plant at our Badlands gas gathering system located in
Bowman County, North Dakota. We also entered into a five-year definitive purchase agreement with a producer and have constructed additional compression facilities and expanded our existing
Badlands gas gathering system into South Dakota.

We
have installed additional gathering and compression infrastructure at our Bakken gathering system to increase the system's capacity from approximately 20,000 Mcf/d to 25,000 Mcf/d and
expanded the existing NGL fractionation facilities at the processing plant to fractionate increased NGL volumes from both the Bakken processing plant and the Badlands processing plant.

We
completed the installation of additional pipelines and compression facilities and increased our system capacity at our Eagle Chief gathering system from approximately 30,000 Mcf/d to
approximately 35,500 Mcf/d due to increased volumes on this system. We completed the construction of a 25,000 Mcf/d natural gas processing facility along our existing Matli gas gathering system which
now provides additional plant processing capacity for increased system volumes. We installed four 10,000 Mcf/d capacity amine-treating facilities at several of our Kinta Area gathering system
locations to remove excess carbon dioxide levels from the natural gas.

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In December 2006, we entered into an agreement to construct and operate gathering pipelines and related facilities associated with the development of a portion of the acreage owned by
CLR in the Woodford shale play in the Arkoma Basin of southeastern Oklahoma. We are in the process installing field gathering, compression and associated equipment. The new gathering system will be
designed to provide low-pressure and highly reliable gathering, compression and dehydration services. The gathering infrastructure is expected to include more than 15,500 horsepower of
compression to provide takeaway capacity in excess of 40,000 Mcf/d. Startup of the initial phase of the project occurred during the second quarter of 2007.

Our Results of Operations

Set forth in the tables below are financial and operating data for our predecessor, CGI, and us for the periods indicated.

Operations
from our Worland gathering system and compression assets contributed to us by Hiland Partners, LLC are reflected only from February 15, 2005, the date of our
initial public offering. Operations from our acquisition of the Bakken gathering system assets are reflected only from

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September 1,
2005. Operations from our acquisition of the Kinta Area gathering assets are reflected only from May 1, 2006.

|                                                                |  | Year Ended December 31 |        
|--------------------------------------------------------------- |  | ---------------------- | -------
|
|
|
|Total Segment Margin Data:                                      |  |                        |        
|Midstream revenues                                              |  | $                      | 273,224
|Midstream purchases                                             |  |                        | 195,212
|                                                                |  |                        |        
|Midstream segment margin                                        |  |                        | 78,012 
|Compression revenues(3)                                         |  |                        | 4,819  
|                                                                |  |                        |        
|Total segment margin(4)                                         |  | $                      | 82,831 
|                                                                |  |                        |        
|Summary of Operations Data:                                     |  |                        |        
|Midstream revenues                                              |  | $                      | 273,224
|Compression revenues                                            |  |                        | 4,819  
|                                                                |  |                        |        
|Total revenues                                                  |  |                        | 278,043
|Operating costs and expenses:                                   |  |                        |        
|Midstream purchases (exclusive of items shown separately below) |  |                        | 195,212
|Operations and maintenance expenses                             |  |                        | 23,279 
|Depreciation, amortization and accretion                        |  |                        | 29,855 
|General and administrative expenses                             |  |                        | 7,587  
|                                                                |  |                        |        
|Total operating costs and expenses                              |  |                        | 255,933
|                                                                |  |                        |        
|Operating income                                                |  |                        | 22,110 
|Other income (expense), net                                     |  |                        | (11,326
|                                                                |  |                        |        
|Net income                                                      |  | $                      | 10,784 
|                                                                |  |                        |        
|Operating Data (unaudited):                                     |  |                        |        
|Inlet natural gas (MCF/d)                                       |  |                        | 215,551
|Natural gas sales (MMBtu/d)                                     |  |                        | 80,731 
|NGL sales (Bbls/d)                                              |  |                        | 4,696  
|Natural gas gathered (MMBtu/d)(5)                               |  |                        | 123,008

---

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Year Ended December 312007

2006

2005Hiland Partners, LP

Hiland Partners, LP(1)

Predecessor(2)

Total(in thousands)Operating income

$
22,110

$
20,298

$
11,963

$
608

$
12,571Add:Operations and maintenance expenses


23,279


16,071


6,579


780


7,359Depreciation, amortization and accretion


29,855


22,130


10,600


512


11,112General and administrative expenses


7,587


4,994


2,304


166


2,470Total segment margin

$
82,831

$
63,493

$
31,446

$
2,066

$
33,512


Year Ended December 31, 2007 Compared with Year Ended December 31, 2006

Revenues.Total revenues (midstream and compression) were $278.0 million for the year ended
December 31, 2007 compared to $219.7 million for the year ended December 31, 2006, an increase of $58.4 million, or 26.6%. This $58.4 million increase was largely
due to (i) revenues associated with natural gas sales volumes related to our Woodford Shale gathering system which commenced production on April 27, 2007, (ii) a full year of
natural gas sales volumes in 2007 related to our acquisition of the Kinta Area gathering assets effective May 1, 2006, (iii) increased natural gas sales volumes at our Eagle Chief and
Bakken gathering systems, (iv) revenues related to increased NGL sales volumes at our Woodford Shale, Bakken, Badlands and Eagle Chief gathering systems and (v) increased average
realized NGL sales prices partially offset by lower average realized natural gas sales prices in 2007 as compared to the same period in 2006. Revenues from compression assets were the same for both
periods.

Our
midstream revenues were $273.2 million for the year ended December 31, 2007 compared to $214.9 million for the year ended December 31, 2006, a net
increase of $58.4 million, or 27.2%. Of this increase in midstream revenues, approximately $57.4 million was attributable to natural gas sales volumes related to our Woodford Shale
gathering system, a full year of natural gas sales volumes and gathering fee volumes in 2007 associated with the Kinta Area gathering assets acquisition effective May 1, 2006 and increased
natural gas and NGL sales volumes at our Bakken, Badlands and Eagle Chief gathering systems. Midstream revenues increased by approximately $12.7 million due to increased NGL sales prices offset
by $11.7 million as a result of lower natural gas sales prices compared to 2006. Our Woodford Shale gathering system, which began production in late April, 2007 accounted for 28.8% of the
$58.4 million increase contributing $16.8 million to midstream revenues.

Inlet
natural gas volumes were 215,551 Mcf/d for the year ended December 31, 2007 compared to 157,556 Mcf/d for the year ended December 31, 2006, an increase of 57,995
Mcf/d, or 36.8%. Of the 57,995 Mcf/d increase, 41,915 Mcf/d, or 72.3% was attributable to inlet Mcf/d at our Kinta Area gathering system for a full year in 2007 which we acquired effective
May 1, 2006, and the remaining 16,080 Mcf/d increase was primarily attributable to inlet Mcf/d at our Woodford Shale gathering system and increased inlet Mcf/d at our Eagle Chief, Bakken and
Badlands gathering systems. Natural gas sales volumes were 80,731 MMBtu/d for the year ended December 31, 2007 compared to 66,947 MMBtu/d for the year ended December 31, 2006, an
increase of 13,784 MMBtu/d, or 20.6%. The increase of 13,784 MMBtu/d was primarily attributable to the increased natural gas volumes as a result

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of
a full year of operations in 2007 at our Kinta Area gathering system which we acquired effective May 1, 2006 and to increased volumes at both our Bakken and Eagle Chief gathering systems and
our new Woodford Shale gathering system, which contributed 4,649 MMBtu/d to the increase in natural gas sales volumes. Our NGL sales volumes were 4,696 Bbls/d for the year ended December 31,
2007 compared to 3,347 Bbls/d for the year ended December 31, 2006, an increase of 1,349 Bbls/d, or 40.3%. Of the 1,349 Bbls/d increase, 443 Bbls/d, or 32.8% was attributable to NGL sales
volumes at our Woodford Shale gathering system and 834 Bbls/d, or 61.8% was attributable to increased NGL sales volumes at our Bakken, Eagle Chief and Badlands gathering systems.

Our
average realized natural gas sales prices were $5.75 per MMBtu for the year ended December 31, 2007 compared to $6.11 per MMBtu for the year ended December 31, 2006, a
decrease of $0.36 per MMBtu, or 5.9%. Our average realized NGL sales prices were $1.18 per gallon for the year ended December 31, 2007 compared to $1.02 per gallon for the year ended
December 31, 2006, an increase of $0.16 per gallon or 15.7%. The change in our average realized natural gas sales prices was primarily a result of lower index prices due to a softening of
supply and demand fundamentals for energy, which caused natural gas prices to fall during the year ended December 31, 2007 compared to the year ended December 31, 2006. The change in our
average realized NGL sales prices was primarily a result of higher index prices due to a tightening of supply and demand fundamentals for energy, which caused NGL prices to rise during the year ended
December 31, 2007 compared to the year ended December 31, 2006.

Net
cash received from our counterparty on cash flow swap contracts that began on May 1, 2006 for natural gas derivative transactions that closed during the year ended
December 31, 2007 was $4.8 million compared to $3.6million for the year ended December 31, 2006. These receipts increased average realized natural gas sales prices by $0.16 per
MMBtu in 2007 and by $0.14 per MMBtu in 2006. Cash paid to our counterparty on cash flow swap contracts that began on September 1, 2006 for NGL derivative transactions that closed during the
year ended December 31, 2007 was $3.0 million. These payments decreased average realized natural gas sales prices by $0.04 per gallon in 2007. Closed NGL derivative transactions during
the year ended December 31, 2006 were insignificant.

Fees
earned from 123,008 MMBtu/d of natural gas gathered, in which we do not take title to the gas, related to our Kinta Area gathering assets we acquired on May 1, 2006 were
$11.1 million for the year ended December 31, 2007. Similar fees earned from May 1, 2006 through December 31, 2006 averaging
127,437 MMBtu/d of natural gas gathered was $7.2 million. The increase of $3.9 million in fees earned was primarily due to a full year of operations in 2007 as compared to eight months
of operations in 2006, and partially attributable to treating fees earned related to the four amine treating facilities installed in early 2007. Gathering fees earned during the year ended December
2007 as compared to the eight month period in 2006 were somewhat offset by a 4,429 MMBtu/d reduction in volumes gathered.

Our
compression revenues were $4.8 million for the each of the year ended December 31, 2007 and 2006.

Midstream Purchases.Our midstream purchases were $195.2 million for the year ended
December 31, 2007 compared to $156.2 million for the year ended December 31, 2006, an increase of $39.0 million, or 25.0%. The $39.0 million increase primarily
consists of $12.8 million, or 32.8% attributable to purchased natural gas from our Woodford Shale gathering system and $10.8 million, or 27.6%, attributable to purchased natural gas from
our Kinta Area gathering assets for a full year of operations in 1007. The remaining increase in midstream purchases was attributable to increased purchased residue gas volumes at our Bakken, Eagle
Chief and Badlands gathering systems. The increase in volumes was offset by reduced payments to producers due primarily to lower natural gas purchase prices, which generally are closely related to
fluctuations in natural gas sales prices.

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Operations and Maintenance.Our operations and maintenance expense totaled $23.3 million for
the year ended December 31, 2007 compared with $16.1 million for the year ended December 31, 2006, an increase of $7.2 million, or 44.9%. Of this increase,
$2.9 million, or 40.0% was attributable to a full year of operations and maintenance expense at our Kinta Area gathering system. Operations and maintenance expense also increased by
$2.5 million, or 35.2% at our Badlands gathering facility largely due to compressor rentals and other related costs associated with our expansion project. Our new Woodford Shale gathering
system contributed $0.9 million to the increase in operations and maintenance expense and our Bakken and Eagle Chief gathering systems, as a result of increased volumes, contributed
$0.8 million to the increase in operations and maintenance expense.

Depreciation, Amortization and Accretion.Our depreciation, amortization and accretion expense
totaled $29.9 million for the year ended December 31, 2007 compared with $22.1 million for the year ended December 31, 2006, an increase of $7.7 million, or 34.9%.
Of this increase, $3.1 million, or 40.1% was attributable to depreciation and amortization on our Kinta Area gathering system for a full year of operations in 2007. The increase is also
attributable to additional depreciation related to our internal organic growth projects completed in 2007 of $1.8 million, or 23.2% at our Bakken gathering system and $1.4 million, or
17.8% at our Badlands gathering system,

General and Administrative.Our general and administrative expense totaled $7.6 million for
the year ended December 31, 2007 compared with $5.0 million for the year ended December 31, 2006, an increase of $2.6 million, or 51.9%. The increase is primarily
attributable to $1.1 million of acquisition evaluation expenses, $0.5 million of non-cash compensation expense related to unit option awards and restricted and phantom unit
awards and $0.5 million due to increased salaries and salary related expenses as a result of additional staffing, including costs of recruitment.

Other Income (Expense).Our other income (expense) totaled ($11.3) million for the year ended
December 31, 2007 compared with ($5.6) million for the year ended December 31, 2006, an increase in expense of $5.7 million. The increase is primarily attributable to additional
interest expense from a full year of borrowings on our credit facility for the acquisition of the Kinta Area gathering assets effective May 1, 2006 and to interest expense for our internal
plant and pipeline expansion projects at our Badlands, Woodford Shale and Bakken gathering systems in 2007.

Year Ended December 31, 2006 Compared with Year Ended December 31, 2005

Revenues.Total revenues (midstream and compression) were $219.7 million for the year ended
December 31, 2006 compared to $166.6 million for the year ended December 31, 2005, an increase of $53.1 million, or 31.9%. This increase was primarily attributable to
(i) increased volumes of 11,799 MMBtu/d of natural gas sales, and 1,267 Bbls/d of NGL sales attributable to our acquisition of the Bakken gathering system effective September 1, 2005,
(ii) increased volumes of approximately 8,428 MMBtu/d of natural gas sales and 127,437 MMBtu/d of natural gas gathered for the eight months ended December 31, 2006 from the Kinta Area
gathering assets we acquired on May 1, 2006, (iii) additional volumes attributable to the Worland gathering system which was contributed to us on February 15, 2005 and
(iv) increased revenues from compression assets also contributed to us on February 15, 2005.

Midstream
revenues were $214.9 million for the year ended December 31, 2006 compared to $162.4 million for the year ended December 31, 2005, an increase of
$52.5 million, or 32.2%. Of this net increase, $137.6 million was attributable to higher residue natural gas and NGL sales volumes offset by a decrease of $85.1 million
attributable to decreased average realized natural gas and NGL prices. Increased volumes in 2006 on the Bakken gathering system we acquired effective September 1, 2005 and on the Kinta Area
gathering assets we acquired on May 1, 2006 represented $41.1 million and $19.7 million, respectively of the increase in midstream revenues. This combined increase of
$60.8 million was primarily offset by a decrease of $8.3 million as a result of lower natural sales gas

60

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and
NGL sales prices in 2006 as compared to 2005. The inclusion of Worland gathering system for the entire year in 2006 as compared to only ten and one-half months in 2005 also contributed
to the volume increase for 2006 as compared to 2005.

Natural
gas sales volumes were 66,947 MMBtu/d for the year ended December 31, 2006 compared to 47,096 MMBtu/d for the year ended December 31, 2005, an increase of 19,851
MMBtu/d, or 42.2%. Of the 19,851 MMBtu/d increase, 11,799 MMBtu/d, or 59.4% was attributable to natural gas volumes as a result of our Bakken gathering system acquisition effective September 1,
2005 and 5,657 MMBtu/d, or 32.1% was attributable to the natural gas volumes as a result of our Kinta Area gathering assets we acquired on May 1, 2006. Our NGL sales volumes were 3,347 Bbls/d
for the year ended December 31, 2006 compared to 1,965 Bbls/d for the year ended December 31, 2005, an increase of 1,385 Bbls/d, or 70.3%. Of the 1,382 Bbls/d increase, 1,267 Bbls/d, or
91.7% was attributable to our Bakken gathering system. Increased volumes at our Eagle Chief gathering system of 3,532 MMBtu/d and 126 Bbls/d also contributed to our overall increase in volumes for
2006 as compared to 2005.

Average
realized natural gas sales prices were $6.11 per MMBtu for the year ended December 31, 2006 compared to $7.39 per MMBtu for the year ended December 31, 2005, a
decrease of $1.28 per MMBtu, or 17.3%. Average realized NGL sales prices were $1.02 per gallon for the year ended December 31, 2006 compared to $1.01 per gallon for the year ended
December 31, 2005, an increase of $0.01 per gallon or 1.0%. The decrease in our average realized natural gas sales prices was primarily a result of lower index prices due to a softening of
supply and demand fundamentals for energy, which caused natural gas prices to fall during the year ended December 31, 2006 compared to the year ended December 31, 2005.

Cash
received from our counterparty on cash flow swap contracts that began on May 1, 2006 for natural gas derivative transactions that closed during the year ended
December 31, 2006 totaled $3.6 million. This gain increased average realized natural gas sales prices to $6.11 per MMBtu from $5.97 per MMBtu, an increase of $0.14 per MMBtu, or 2.3%. We
had no closed derivative transactions during the year ended December 31, 2005.

Fees
earned from an eight-month average of 127,437 MMBtu/d of natural gas gathered, in which we do not take title to the gas, related to our Kinta Area gathering assets we acquired on
May 1, 2006 were $7.2 million for the year ended December 31, 2006. The eight-month average of 127,437 MMBtu/d equates to an average 85,540 MMBtu/d for the year ended
December 31, 2006. We had no similar fees from natural gas gathering during the year ended December 31, 2005.

Compression
revenues were $4.8 million for the year ended December 31, 2006 compared to $4.2 million for the year ended December 31, 2005, an increase of
$0.6 million or 14.3%. The compression assets were contributed to us by Hiland Partners, LLC on February 15, 2005. Accordingly, revenues from these assets were only included for
ten and one-half months of the year ended December 31, 2005.

Midstream Purchases.Midstream purchases were $156.2 million for the year ended
December 31, 2006 compared to $133.1 million for the year ended December 31, 2005, an increase of $23.1 million, or 17.4%. Purchases increased by $25.9 million as a
result of increased natural gas and NGL volumes as a result of our Bakken gathering system acquisition effective September 1, 2005 and by $9.3 million from
increased natural gas volumes from our Kinta Area gathering assets acquisition which began on May 1, 2006. This combined increase of $35.2 million was primarily offset by
$12.1 million in reduced payments to producers due to lower natural gas and NGL purchase prices, which generally are closely related to fluctuations in natural gas and NGL sales prices.

Operations and Maintenance.Operations and maintenance expense totaled $16.1 million for the
year ended December 31, 2006 compared with $7.4 million for the year ended December 31, 2005, an increase of $8.7 million, or 118.4%. Of this increase, $4.6 million,
or 53.2% was attributable to

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operations
and maintenance as a result of our Kinta Area gathering assets we acquired on May 1, 2006 and $2.4 million, or 27.2% was attributable to operations and maintenance at our
Bakken gathering system we acquired effective September 1, 2005. Higher costs of chemicals and lube oil, combined with increased wages due to internal expansions caused an increase in
operations and maintenance of $1.5 million in our Eagle Chief, Matli, Badlands and Worland gathering systems in 2006 as compared to 2005.

Depreciation, Amortization and Accretion.Depreciation, amortization and accretion expense totaled
$22.1 million for the year ended December 31, 2006 compared with $11.1 million for the year ended December 31, 2005, an increase of $11.0 million, or 99.2%. Of this
increase, $5.3 million, or 48.5% was attributable to depreciation and amortization on our Kinta Area gathering assets we acquired on May 1, 2006 and $4.6 million, or 42.2% was
attributable to depreciation and amortization on our Bakken gathering system we acquired effective September 1, 2005. Depreciation at our Eagle Chief, Matli, Badlands and Worland gathering
systems increased by $0.5 million in 2006 as compared to 2005 as a result of internal capital expansions completed in 2006.

General and Administrative.General and administrative expense totaled $5.0 million for the
year ended December 31, 2006 compared with $2.5 million for the year ended December 31, 2005, an increase of $2.5 million, or 102.2%. The increase is primarily attributable
to increased salaries and additional staffing of $0.9 million as a result of growth and $0.8 million in Sarbanes-Oxley internal control compliance costs and audit and tax preparation
fees.

Other Income (Expense).Other income (expense) totaled ($5.6) million for the year ended
December 31, 2006 compared with ($2.2) million for the year ended December 31, 2005, an increase in expense of $3.4 million. Interest expense increased $3.6 million. The
increase is primarily attributable to interest expense associated with borrowings of $61.2 million on our credit facility to partially finance the Kinta Area gathering assets we acquired on
May 1, 2006, the interest expense associated with the partial financing of the acquisition of the Bakken gathering system effective September 1, 2005 and additional interest expense on
$62.1 million invested in maintenance and expansion capital expenditure projects in 2006 as compared to $10.4 million in 2005.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us, and information currently
available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our expectations may vary materially from actual results. Please see
"Forward Looking Statements."

U.S. Gas Supply and Outlook.We believe that current natural gas prices will continue to result in relatively high levels of
natural gas-related drilling as producers seek to increase their level of natural gas production. Although the number of U.S. natural gas wells drilled has increased overall in recent
years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries. We believe that an increase in U.S. drilling activity and additional sources of
supply such as liquefied natural gas 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 favorable natural gas prices, new discoveries and the implementation of new
exploration and production techniques. We believe that this higher level of activity will continue. We also believe that our Badlands gathering system is located in an area where ongoing secondary
recovery operations will provide us with additional natural gas volumes.

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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.

Midstream Segment Margins.During 2007, our midstream segment margins were positively impacted due to increased volumes and
NGL prices but were negatively impacted due to reduced natural gas prices resulting in a net increase in margins from 2006. During 2006, our midstream segment margins were positively impacted due to
increased volumes but were negatively impacted due to reduced natural gas prices and NGL prices, resulting in a net increase in margins from 2005. Our profitability is dependent upon pricing and
market demand for natural gas and NGLs, which are beyond our control and have been volatile.

Interest Rate Environment.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

Overview

Cash generated from operations, borrowings under our credit facility and funds from private and future public equity and debt offerings are our primary sources of
liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditure
requirements. Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, and more broadly, on the
availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

Cash Flows

Year ended December 31, 2007 Compared to Year ended December 31, 2006

Cash Flows from Operating Activities.Our cash flows from operating activities increased by $1.1 million to
$40.7 million for the year ended December 31, 2007 from $39.6 million for the year ended December 31, 2006. During the year ended December 31, 2007, we received cash
flows from customers of approximately $269.3 million, had cash payments to our suppliers and employees of approximately $217.3 million and payment of interest expense of
$11.3 million, net of amounts capitalized, resulting in cash received from our operating activities of $40.7 million. During the year ended December 31, 2006, we received cash
flows from customers of approximately $218.0 million, had

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cash
payments to our suppliers and employees of approximately $173.0 million and payment of interest expense of $5.4 million, net of amounts capitalized, resulting in cash received from
our operating activities of $39.6 million. Changes in cash receipts and payments are primarily due to the timing of collections at the end of our reporting periods. We collect and pay large
receivables and payables at the end of each calendar month. The timing of these payments and receipts may vary by a day or two between month-end periods and cause fluctuations in cash
received or paid. Natural gas and NGL volumes from our new Woodford Shale gathering system and increased natural gas and NGL volumes from our Bakken, Badlands and Eagle Chief gathering systems
combined with increased NGL sales prices, but offset by lower natural gas sales prices contributed to increases in accounts receivable, accrued midstream revenues, accounts payable and accrued
midstream purchases during the year ended December 31, 2007. Working capital items, exclusive of cash, used $0.9 million in cash flows from operating activities and contributed
$2.1 million to cash flows from operating activities during the year ended December 31, 2007 and 2006, respectively. Net income for the year ended December 31, 2007 was
$10.8 million, a decrease of $3.9 million from a net income of $14.7 million for the year ended December 31, 2006. Depreciation, amortization and accretion increased by
$7.7 million or 20.9%, to $29.7 million for the year ended December 31, 2007 from $22.1 million for the year ended December 31, 2006.

Cash Flows Used for Investing Activities.Our cash flows used for investing activities representing our internal organic
growth investments in property and equipment, increased by $21.3 million to $83.4 million for the year ended December 31, 2007 from $62.1 million for the year ended
December 31, 2006. This $21.3 million increase is largely attributable to cash invested at our new Woodford Shale gathering system, our Badlands expansion project and continued growth at
our Bakken gathering system. We had no asset acquisitions in 2007. In May 2006, $96.4 million of cash flows was used for our Kinta Area gathering assets acquisition.

Cash Flows from Financing Activities.Our cash flows from financing activities decreased by $80.2 million to
$42.8 million for the year ended December 31, 2007 from $123.0 million for the year ended December 31, 2006. During the year ended December 31, 2007, we borrowed
$74.0 million under our credit facility to fund our internal expansion projects, received capital contributions of $1.1 million as a
result of issuing common units due to the exercise of 42,660 vested unit options, made capital lease obligation payments of $0.3 million, distributed $31.3 million to our unitholders,
incurred offering costs of $0.2 million associated with our S-3/A registration statement filed with the SEC on January 23, 2007 and paid debt issuance costs of
$0.5 million associated with our third amended credit facility. During the year ended December 31, 2006, we borrowed $113.3 million under our credit facility to partially fund the
Kinta Area gathering assets acquisition on May 1, 2006 and to fund our internal expansion projects at both our Badlands and Bakken gathering systems. Also during the year ended
December 31, 2006, we received capital contributions of $35.0 million from our general partner in exchange for the issuance of 761,714 common units and general partner equivalent units,
received $1.3 million as a result of issuing common units due to the exercise of 52,699 vested unit options, paid debt issuance costs of $0.9 million and distributed $25.6 million
to our unitholders.

Year ended December 31, 2006 Compared to Year ended December 31, 2005

Cash Flows from Operating Activities.Our cash flows from operating activities increased by $31.5 million to
$39.6 million for the year ended December 31, 2006 from $8.1 million for the year ended December 31, 2005. Approximately $19.7 million of the increase is
attributable to higher net income plus depreciation and amortization during the year ended December 31, 2006 as compared to the year ended December 31, 2005. In addition, changes in
working capital items exclusive of cash contributed $2.0 million to cash flows from operating activities during the year ended December 31, 2006 as compared to reducing cash flows from
operating activities by $13.8 million for the year ended December 31, 2005. The use of cash in operating activities in 2005 was primarily a result of

64

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replenishing
our accounts receivable after the closing of our initial public offering and increased accounts receivable as a result of higher realized prices for natural gas and NGLs at
December 31, 2005. In connection with our formation, $9.1 million of CGI accounts receivables was retained by former owners of CGI. Accounts receivables increased at December 31,
2006 as compared to December 31, 2005 as a result of receivables related to our acquisition of the Kinta Area gathering assets, but were offset by decreased natural gas and NGL prices at
December 31, 2006 as compared to natural gas and NGL prices at December 31, 2005. Accounts payable and accrued midstream purchases as of December 31, 2006 increased due to
increased vendor payables relating to internal expansion and growth projects and additional accounts payable relating to the operations of the Kinta Area gathering assets acquired on May 1,
2006, both of which were offset by a reduction in midstream purchases payable due to reduced natural gas and NGL purchase prices at December 31, 2006 as compared to natural gas and NGL prices
at December 31, 2005.

Cash Flows Used for Investing Activities.Cash flows used in investing activities, which represent investments in property
and equipment and payments made for acquisitions, increased to $158.4 million from $74.9 million, an increase of $83.5 million for the year ended December 31, 2006 as
compared to the year ended December 31, 2005. The increase is primarily a result of the Kinta Area gathering assets
acquisition on May 1, 2006, the ongoing progress on our Badlands expansion project, continued growth at our Bakken gathering system and various other internal expansion projects.

Cash Flows from Financing Activities.Our cash flows from financing activities increased to $123.0 million for the
year ended December 31, 2006 from $72.7 million for the year ended December 31, 2005. During the year ended December 31, 2006, we borrowed $113.3 million under our
credit facility to partially fund the Kinta Area gathering assets acquisition on May 1, 2006 and to fund our internal expansion projects at Badlands, Kinta and Bakken. During the year ended
December 31, 2006, we received capital contributions of $35.0 million from our general partner in exchange for the issuance of 761,714 common units and 15,545 general partner equivalent
units and $1.3 million as a result of issuing common units due to the exercise of 47,533 vested unit options. During the year ended December 31, 2006, we incurred $0.9 million of
debt issuance costs and distributed $25.6 million to our unitholders. We completed our initial public offering of 2,300,000 common units on February 15, 2005, receiving net proceeds of
$48.1 million. The proceeds from the public offering were used to (1) pay remaining offering costs of $2.2 million and deferred debt issuance costs of $0.6 million,
(2) pay outstanding indebtedness of $22.9 million, (3) redeem $6.3 million of common units from an affiliate of Harold Hamm and the Hamm Trusts, and (4) make a
$3.9 million distribution to the previous owners of Hiland Partners, LLC. We retained $12.2 million to replenish working capital. During the period from January 1, 2005 to
February 14, 2005, CGI repaid $1.1 million of its outstanding indebtedness.

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:



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."

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Total Contractual Cash Obligations.A summary of our total contractual cash obligations as of December 31, 2007 is
presented below:

|                                               |  |   |         | Payment Due by Period |   |      
|---------------------------------------------- |  | - | ------- | --------------------- | - | -----
|
|
|Senior secured revolving credit facility(1)    |  | $ | 221,064 |                       | $ |     
|Capital lease obligations(2)                   |  |   | 8,561   |                       |   | 1,184
|Operating leases, service agreements and other |  |   | 3,593   |                       |   | 1,541
|                                               |  |   |         |                       |   |      
|Total contractual cash obligations             |  | $ | 233,218 |                       | $ | 2,725
|                                               |  |   |         |                       |   |      

---

Financial Derivatives and Commodity Hedges.We have entered into certain financial derivative instruments that are classified
as cash flow hedges in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," SFAS No. 133, as
amended, and relate to forecasted sales in 2007 and 2008. We entered into these instruments to hedge the forecasted natural gas and NGL sales or purchases against the variability in expected future
cash flows attributable to changes in market prices. The swap instruments are contractual agreements between a counterparty and us to exchange obligations of money as the underlying natural gas or
NGLs are sold or purchased. Under these swap agreements, we either receive or pay a monthly net settlement that is determined by the difference between a fixed price and a floating price based on
certain indices for the relevant contract period for the agreed upon volumes. The following table provides information about our financial derivative instruments at December 31, 2007:

|Description and Production Period                       |  | Volume    |  | Average
Fixed/Open
Price |  | Fair Value
Asset
(Liability) |       
|------------------------------------------------------- |  | --------- |  | ------------------------ |  | ---------------------------- | ------
|Natural GasSold Fixed for Floating Price Swaps         |  | (MMBtu)   |  | (per MMBtu)              |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2008 - December 2008                            |  | 1,980,000 |  | $7.84                    |  | $                            | 2,718 
|January 2009 - December 2009                            |  | 1,068,000 |  | $7.06                    |  |                              | (141  
|                                                        |  |           |  |                          |  |                              |       
|                                                        |  |           |  |                          |  | $                            | 2,577 
|                                                        |  |           |  |                          |  |                              |       
|Natural GasSold Open for Floating Price Swaps(1)       |  | (MMBtu)   |  | (per MMBtu)              |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2009 - December 2009                            |  | 1,068,000 |  | $7.35                    |  | $                            | 418   
|                                                        |  |           |  |                          |  |                              |       
|Natural GasBuy Fixed for Floating Price Swaps          |  | (MMBtu)   |  | (per MMBtu)              |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2008 - December 2008                            |  | 790,569   |  | $7.33                    |  | $                            | (554  
|                                                        |  |           |  |                          |  |                              |       
|Natural Gas LiquidsSold Fixed for Floating Price Swaps |  | (Bbls)    |  | (per Gallon)             |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2008 - December 2008                            |  | 441,768   |  | $1.30                    |  | $                            | (7,684
|                                                        |  |           |  |                          |  |                              |       

---

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Fixed Price Physical Forward Sales Contracts.We have executed one natural gas fixed price physical forward sales contract on
100,000 MMBtu per month for 2008 with a fixed price of $8.43 per MMBtu. This contract has been designated as a normal sale under SFAS No. 133 and is therefore not marked to market as a
derivative.

Off-Balance Sheet Arrangements.We had no significant off-balance sheet arrangements as of
December 31, 2007or December 31, 2006..

Credit Facility

On February 6, 2008, we entered into a fourth amendment to our credit facility dated as of February 15, 2005. Pursuant to the fourth amendment, we
have, among other things, increased our borrowing base from $250 million, to $300 million and decreased the accordion feature in the facility from $100 million to
$50 million. Our original credit facility dated May 2005 was first amended in September 2005, amended a second time in June 2006 and amended a third time in July 2007.

The
fourth amendment increases our borrowing capacity under our senior secured revolving credit facility to $300 million such that the facility now consists of a
$291 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
"Acquisition Facility") and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distributions (the "Working Capital Facility").

In
addition, the fourth amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to
$50 million and allows for the issuance of letters of credit of up to $15 million in the aggregate. The senior secured revolving credit facility also requires us to meet certain
financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain
permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and
a minimum interest coverage ratio of 3.0:1.0. The credit facility will
mature in May 2011. 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.

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 125 basis points per
annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per
annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect
on such day plus 1/2 of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to
1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility.
During any step-up period, the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be
increased by 12.5 basis points per annum. At December 31, 2007, the interest rate on outstanding borrowings from our credit facility was 7.19%.

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

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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 its business, amend its material agreements, including the Omnibus Agreement or enter into a
merger, consolidation or sale of assets.

The
credit facility defines EBITDA as our consolidated net income, plus income tax expense, interest expense, depreciation and amortization expense, amortization of intangibles and
organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary
items.

Upon
the occurrence of an event of default as defined in 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.

The
credit facility limits distributions to our unitholders to available cash, as defined by the agreement, and borrowings to fund such distributions are only permitted under the
revolving working capital facility. The revolving working capital facility is subject to an annual "clean-down" period of 15 consecutive days in which the amount outstanding under the
revolving working capital facility is reduced to zero.

As
of December 31, 2007, we had $221.1 million outstanding under the credit facility and were in compliance with its financial covenants.

Recent Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations." This statement amends and replaces SFAS No. 141, but retains the
fundamental requirements in SFAS No. 141 that the purchase method of accounting be used for all business combinations and an acquirer be identified for each business combination. The statement
provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any non-controlling interest in the acquiree. SFAS 141(R) provides
for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. The statement also determines what information to disclose to enable
users to be able to evaluate the nature and financial effects of the business combination. The provisions of SFAS 141(R) apply prospectively to business combinations for which the acquisition
date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and do not allow early adoption. We are evaluating the new requirements of
Statement No. 141(R) and the impact it will have on business combinations completed in 2009 or thereafter.

In
December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statementsan amendment of ARB No. 51." SFAS No. 160
establishes accounting and reporting standards that require the ownership interests in subsidiaries held by parties other than the parent (minority interest) be clearly identified, labeled, and
presented in the consolidated balance sheet within equity, but separate from the parent's equity. SFAS No. 160 requires the equity amount of consolidated net income attributable to the parent
and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent's ownership interest while the parent retains its
controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income will be determined without
deducting minority interest; however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent's shareholders.
Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent's ownership interest in a subsidiary that does not result in deconsolidation and that the parent
recognize a gain or loss in net income when a subsidiary is

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deconsolidated.
SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not permitted. We do not expect this Statement will have a material
impact on our financial position, results of operations or cash flows.

In
February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities". SFAS No. 159 expands opportunities to use fair value
measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for fiscal years
beginning after November 15, 2007. This Statement was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at
fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our financial position, results of
operations or cash flows.

In
September 2006, the FASB issued SFAS No. 157 "Fair Value Measurements." SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP)
such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair
value measurements based on their level in the hierarchy. This Statement applies to derivatives and other financial instruments, which Statement 133,Accounting for Derivative
Instruments and Hedging Activities, as amended, requires be measured at fair value at initial recognition and for all subsequent periods. This Statement is effective for
financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will apply the provisions of this Statement prospectively in the
first quarter of 2008 and do not expect any significant impact on our financial position, results of operations or cash flows.

Significant Accounting Policies and Estimates

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 for compression services are recognized when the services under the agreement are performed. Revenues from oil and gas production (discontinued operations)
were recorded in the month produced and title was transferred to the purchaser.

Depreciation and Amortization.Depreciation of all equipment is determined under the straight-line method using
various rates based on useful lives, 10 to 22 years for pipeline and processing plants, and 3 to 10 years for corporate and other assets. The cost of assets and related accumulated
depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Maintenance, repairs and minor replacements are expensed
as incurred. Costs of replacements constituting improvement are capitalized. Intangible assets consist of the acquired value of existing contracts to sell natural gas and other NGLs, compression
contracts and identifiable customer relationships, which do not have significant residual value. The contracts are being amortized over their estimated lives of ten years.

Derivatives.We utilize derivative financial instruments to reduce commodity price risks. We do not hold or issue derivative
financial instruments for trading purposes. Statement of Financial Accounting Standards (or SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities", which was amended in
June 2000 by SFAS No. 138 and in May 2003 by SFAS No. 149, establishes accounting and reporting standards for derivative instruments and hedging activities. It requires that an entity
recognize all derivatives as either assets or liabilities in the statement of financial condition and measure those instruments at fair value. Derivatives that are not designated as hedges are
adjusted to fair value through income. If the derivative is designated as a hedge, depending upon the nature of the hedge, changes in the fair value of the derivatives are either offset against the
fair

69

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value
of assets, liabilities or firm commitments through income, or recognized in other comprehensive income until the hedged item is recognized in income. The ineffective portion of a derivative's
change in fair value is immediately recognized into income. If a derivative no longer qualifies for hedge accounting the amounts in accumulated other comprehensive income will be immediately charged
to operations.

Asset Retirement Obligations.SFAS No. 143 "Accounting for Asset Retirement Obligations" requires entities to record
the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method and the liability is accreted to measure the change in liability due to the passage of time. The
primary impact of this standard relates to our estimated costs for dismantling and site restoration of certain of our plants and pipelines. Estimating future asset retirement obligations requires us
to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset
retirement obligation to determine the fair value, generally as estimated by third party consultants. The present value calculation requires us to make numerous assumptions and judgments, including
the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political
environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required to the
related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any
significant variance in any of the above assumptions or factors could materially affect our cash flows.

Impairment of Long-Lived Assets.In accordance with Statement of Financial Accounting Standards (SFAS)
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", we evaluate our long-lived assets, including intangible assets, of identifiable business
activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether
impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If impairment has occurred, the
amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified
to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed
of, an estimate of the fair value is re-determined when related events or circumstances change.

When
determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our
estimate of cash flows is based on assumptions regarding the volume of reserves providing asset cash flow and future NGL product and natural gas prices. The amount of reserves and drilling activity
are dependent in part on natural gas prices. Projections of reserves and future commodity prices are inherently subjective and contingent upon a number of variable factors, including, but not limited
to:



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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.

Share Based Compensation.In October 1995 the FASB issued SFAS No. 123, "Share-Based Payment," which was revised in
December 2004 ("SFAS 123R"). SFAS 123R requires that the compensation cost relating to share-based payment transactions be recognized in the financial statements and that cost be
measured based on the fair value of the equity or liability instruments issued. We adopted SFAS 123R as of January 1, 2006 and applied SFAS 123R using the permitted modified
prospective method beginning as of the same date and our unearned deferred compensation of $289 as of January 1, 2006 has been eliminated against common unit equity. Prior to January 1,
2006 we recorded any unamortized compensation related to restricted unit awards as unearned compensation in equity. We expect no change to our cash flow presentation from the adoption of
SFAS 123R since no tax benefits are recognized by us as a pass through entity.

We
estimate the fair value of each option granted on the date of grant using the American Binomial option-pricing model. In estimating the fair value of each option, we use our peer
group volatility averages as determined on the option grant dates. We calculate expected lives of the options under the simplified method as prescribed by the SEC Staff Accounting Bulletin 107 and
have used a risk free interest rate based on the applicable U.S. Treasury yield in effect at the time of grant. Our compensation expense for these awards is recognized on the graded vesting
attribution method. Units
to be issued under our unit incentive plan may be from newly issued units. Prior to our adoption of SFAS 123R on January 1, 2006, we applied Accounting Principles Board Opinion
No. 25 and related interpretations in accounting for our unit-based compensation awards.

Disclosure Regarding Forward-Looking Statements

This annual report on Form 10-K includes certain "forward-looking statements" within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. These statements include statements regarding our plans, goals, beliefs or current expectations. Statements using words such as
"anticipate," "believe," "intend," "project," "plan," "continue," "estimate," "forecast," "may," "will," or similar expressions help identify forward-looking statements. Although we believe such
forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

Actual
results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results
are subject to uncertainties and risks, difficult to predict, and beyond management's control. Such factors include:



71

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These
factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Our
future results will depend upon various other risks and uncertainties, including, but not limited to those described under "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of OperationsRisk Factors Related to our Business." Other unknown or unpredictable factors also could have material adverse effects on our future results. You should not put
undue reliance on any forward-looking statements. All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement. We undertake no duty to update our
forward-looking statements.

Item 7A.    Quantitative and Qualitative Disclosures about Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk
for natural gas and NGLs. We also incur, to a lesser extent, risks related to interest rate fluctuations. We do not engage in commodity energy trading activities.

Commodity Price Risks.Our profitability is affected by volatility in prevailing NGL and natural gas prices. Historically,
changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices are volatile and are impacted by changes in the supply and
demand for NGLs and natural gas, as well as market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read "Risk FactorsRisk Factors Related to our
BusinessOur cash flow is affected by the volatility of natural gas and NGL product prices, which could adversely affect our ability to make distributions to unitholders." To illustrate
the impact of changes in prices for natural gas and NGLs on our operating results, we have provided the table below,

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which
reflects, for the year ended December 31, 2007, the impact on our total segment margin of a $0.01 per gallon change (increase or decrease) in NGL prices coupled with a $0.10 per MMBtu
change (increase or decrease) in the price of natural gas.

Natural Gas Price Change
($/MMBtu)$0.10


$(0.10)NGL Price

$
0.01

$
642,000

$
194,000Change ($/gal)

$
(0.01
)
$
(207,000
)
$
(645,000
)


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.

We
manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, optimization of our assets and the use of derivative contracts.
As a result of these derivative contracts, we have hedged a portion of our expected exposure to natural gas prices and NGL prices in 2008 and 2009. We continually monitor our hedging and contract
portfolio and expect to continue to adjust our hedge position as conditions warrant. The following table provides information about our derivative instruments at December 31, 2007 for the
periods indicated:

|Description and Production Period                       |  | Volume    |  | Average
Fixed/Open
Price |  | Fair Value
Asset
(Liability) |       
|------------------------------------------------------- |  | --------- |  | ------------------------ |  | ---------------------------- | ------
|Natural GasSold Fixed for Floating Price Swaps         |  | (MMBtu)   |  | (per MMBtu)              |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2008 - December 2008                            |  | 1,980,000 |  | $7.84                    |  | $                            | 2,718 
|January 2009 - December 2009                            |  | 1,068,000 |  | $7.06                    |  |                              | (141  
|                                                        |  |           |  |                          |  |                              |       
|                                                        |  |           |  |                          |  | $                            | 2,577 
|                                                        |  |           |  |                          |  |                              |       
|Natural GasSold Open for Floating Price Swaps(1)       |  | (MMBtu)   |  | (per MMBtu)              |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2009 - December 2009                            |  | 1,068,000 |  | $7.35                    |  | $                            | 418   
|                                                        |  |           |  |                          |  |                              |       
|Natural GasBuy Fixed for Floating Price Swaps          |  | (MMBtu)   |  | (per MMBtu)              |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2008 - December 2008                            |  | 790,569   |  | $7.33                    |  | $                            | (554  
|                                                        |  |           |  |                          |  |                              |       
|Natural Gas LiquidsSold Fixed for Floating Price Swaps |  | (Bbls)    |  | (per Gallon)             |  |                              |       
|                                                        |  |           |  |                          |  |                              |       
|January 2008 - December 2008                            |  | 441,768   |  | $1.30                    |  | $                            | (7,684
|                                                        |  |           |  |                          |  |                              |       

---

In
addition to the derivative instruments noted in the table above, we have executed one natural gas fixed price physical forward sales contract on 100,000 MMBtu per month for 2008 with
a fixed price of $8.43 per MMBtu. This contract has been designated as a normal sale under SFAS No. 133 and is therefore not marked to market as a derivative.

Interest Rate Risk.We are exposed to changes in interest rates as a result of our credit facility, which has floating
interest rates. As of December 31, 2007, we had approximately $221.1 million of indebtedness outstanding under our credit facility. The impact of a 100 basis point increase or decrease
in interest rates on this amount of debt would result in an increase or decrease in interest expense, and a corresponding decrease or increase in net income of approximately $2.2 million
annually.

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Credit Risk.Counterparties pursuant to the terms of their contractual obligations expose us to potential losses as a result
of nonperformance. OGE Energy Resources, Inc., SemStream, L.P., ConocoPhillips, Inc. and Montana-Dakota Utilities Co. were our largest customers for the year ended
December 31, 2007, accounting for approximately 19%, 19%, 12% and 11%, respectively, of our revenues. Consequently, changes within one or more of these companies' operations have the potential
to impact, both
positively and negatively, our credit exposure. Our counterparty for all of our derivative instruments as of December 31, 2007 is BP Energy Company.

Item 8.    Financial Statements and Supplementary Data

The See our Financial Statements beginning on page F-1 for the information required by this Item.

Item 9.    Changes in and Disagreements on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures



As
required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended, we have evaluated, under the supervision and with the participation of our
management, including our
principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Based upon that evaluation, our principal executive officer
and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2007, to ensure that information is accumulated and communicated to our
management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized
and reported within the time periods specified in the rules and forms of the SEC.



During
the three months ended December 31, 2007, there were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and
15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Internal Control Over Financial Reporting

See "Managements Report on Internal Control over Financial Reporting on page F-2.

Item 9B.    Other Information

There have been no events that occurred in the fourth quarter of 2007 that would need to be reported on Form 8-K that have not been previously
reported.

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PART III

Item 10.    Directors and Executive Officers of the Registrant

As is the case with many publicly traded partnerships, we do not have officers, directors or employees. Our operations and activities are managed by our general
partner, Hiland Partners GP, LLC. References to our directors and officers are references to the directors and officers of Hiland Partners GP, LLC. Unitholders do not
directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders, as limited by our partnership agreement.

Directors
are elected for one-year terms. The following table shows information regarding the current directors and executive officers of Hiland
Partners GP, LLC.

|Name                 |  | Age |  | Position with Hiland Partners GP, LLC                                  
|-------------------- |  | --- |  | -----------------------------------------------------------------------
|Harold Hamm          |  | 62  |  | Chairman of the Board of Directors                                     
|Joseph L. Griffin    |  | 47  |  | Chief Executive Officer, President and Director                        
|Ken Maples           |  | 45  |  | Chief Financial Officer, Vice PresidentFinance, Secretary and Director
|Robert Shain         |  | 57  |  | Vice PresidentOperations and Engineering                              
|Matthew S. Harrison  |  | 37  |  | Vice PresidentBusiness Development                                    
|Michael L. Greenwood |  | 52  |  | Director                                                               
|Edward D. Doherty    |  | 72  |  | Director                                                               
|Rayford T. Reid      |  | 59  |  | Director                                                               
|Shelby E. Odell      |  | 68  |  | Director                                                               
|John T. McNabb, II   |  | 63  |  | Director                                                               
|Dr. David L. Boren   |  | 66  |  | Director                                                               

Harold Hammwas elected Chairman of the Board of Directors of our general partner in October 2004 and serves as chairman of the
compensation committee of the board of directors of our general partner. Mr. Hamm has served as chairman of the board of directors of the general partner of Hiland Holdings GP, LP
since September 2006 and also serves as chairman of the compensation committee of the board of directors of Hiland Holdings GP, LP's general partner. Mr. Hamm served as President
and Chief Executive Officer and as a director of Continental Gas, Inc. since December 1994 and then served as Chief Executive Officer and a director to 2004. Since its inception in 1967 until
October 2005, Mr. Hamm served as President and Chief Executive Officer and a director of Continental Resources, Inc. and currently serves as its Chief Executive Officer and Chairman of
its board of directors. Mr. Hamm is also immediate past President of the National Stripper Well Association, a member of the executive board of the Oklahoma Independent Petroleum Association
and a member of the executive board of the Oklahoma Energy Explorers. In addition, Mr. Hamm is a director of Complete Production Services, Inc., a publicly traded oilfield service
company.

Joseph L. Griffinwas appointed Chief Executive Officer, President and a director of our general partner in June 2007. Mr. Griffin
has served as a director of the general partner of Hiland Holdings GP, LP since June 2007. Mr. Griffin has more than 20 years of experience in the midstream natural gas
industry. From
2004 to June 2007, Mr. Griffin served as executive vice president over multiple facets of the business of Lumen Midstream Partnership, a subsidiary of the Southern Ute Indian Tribe, in Tulsa,
OK. In 1989, Mr. Griffin co-founded Lumen Midstream, held various senior level management positions and served as a director until Lumen was sold in 2004 to the Southern Ute Indian
Tribe. Mr. Griffin holds a Bachelor of Science degree in Business Administration from Oklahoma State University and is also a Certified Public Accountant.

Ken Mapleswas appointed Chief Financial Officer, Vice PresidentFinance, Secretary and a director of our general partner in
October 2004. Mr. Maples has served as a director of the general partner of Hiland Holdings GP, LP since September 2006. Mr. Maples has served as Chief Financial

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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 a Masters of Business Administration degree from Louisiana State University.

Robert Shainwas elected as our Vice President Northern Region Operations & Engineering in March 2006 and was appointed Vice
President-Operations and Engineering in June 2006. Mr. Shain has over 30 years of experience in the oil and gas industry. The majority of his experience has been in the engineering and
operations of midstream natural gas gathering, compression, processing and treating, along with business development and marketing. From July 2003 until March 2006, Mr. Shain served as Vice
President of Operations and Engineering for Seminole Gas Company, LLC (successor to Impact Energy, LTD) in Tulsa, Oklahoma. From May 1995 until July 2003 Mr. Shain served in a
variety of commercial roles, most recently of which was Vice President of Commercial Services, for CMS Field Services, LLC (successor to Heritage Gas Services, LLC) also in Tulsa,
Oklahoma, in which he was responsible for the development and management of operating and capital budgets.

Matthew S. Harrisonwas appointed Vice President of Business Development in February 2008. Mr. Harrison joined Hiland from Wachovia
Securities where he most recently was a director for its Energy & Power Mergers & Acquisitions Group. Prior to joining Wachovia in 2007, Mr. Harrison spent eight years with A.G.
Edwards Capital Markets' Mergers & Acquisitions Group, most recently leading its energy mergers & acquisitions effort. Prior to joining A.G. Edwards, Mr. Harrison spent five years
with Price Waterhouse as a senior accountant. He holds a B.S. degree in Accounting from the University of Tennessee, a Masters of Business Administration degree from the Kellogg Graduate School of
Management at Northwestern University and is a Certified Public Accountant.

Michael L. Greenwoodwas elected as a director of our general partner in February 2005, and serves as chairman of the audit committee of
our general partner. Mr. Greenwood has served as a director of the general partner of Hiland Holdings GP, LP since September 2006, and serves as chairman of the audit committee of
the board of directors of Hiland Holdings GP, LP's general partner. Mr. Greenwood is founder and managing director of Carnegie Capital LLC, a financial advisory services
firm providing investment banking assistance to the energy industry. Mr. Greenwood previously served as Vice
PresidentFinance and Treasurer of Energy Transfer Partners, L.P. until August 2004. Prior to its merger with Energy Transfer, Mr. Greenwood served as Vice President and
Chief Financial Officer & Treasurer of Heritage Propane Partners, L.P. from 2002 to 2003. Prior to joining Heritage Propane, Mr. Greenwood was Senior Vice President, Chief
Financial Officer and Treasurer for Alliance Resource Partners, L.P. from 1994 to 2002. Mr. Greenwood has over 25 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. Dohertywas elected as a director of our general partner in February 2005, and serves as a member of the audit committee of the
board of directors of our general partner. Mr. Doherty has served as a director of the general partner of Hiland Holdings GP, LP since September 2006, and serves as a member of
the audit committee of the board of directors of Hiland Holdings GP, LP's general partner. Since March 2006, Mr. Doherty has been a partial owner and CEO of ANZ Terminals
Pty. Ltd., an Australian company which owns and operates eight liquid storage terminals in Australia and New Zealand. Mr. Doherty also provides consulting services on terminal
acquisitions. Mr. Doherty served as the Chairman and Chief Executive Officer of Kaneb Pipe Line Company LLC, the general partner of Kaneb Pipe Line Partners L.P. since its
inception in September 1989 until July 2005. Prior to joining Kaneb, Mr. Doherty was President and Chief Executive Officer of two private companies, which provided restructuring services to
troubled companies and was President and Chief Executive Officer of

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Commonwealth
Oil Refining Company, Inc., a public refining and petrochemical company. Mr. Doherty holds a Bachelor of Arts degree from Lafayette College and a Doctor of Jurisprudence
from Columbia University School of Law.

Rayford T. Reidwas elected as a director of our general partner in May 2005, and serves as a member of the compensation committee of the
board of directors of our general partner. Mr. Reid has served as a director of the general partner of Hiland Holdings GP, LP since September 2006, and serves as a member of the
compensation committee of the board of directors of Hiland Holdings GP, LP's general partner. Mr. Reid has more than 30 years of investment banking, financial advisory and
commercial banking experience, including 25 years focused on the oil and gas industry. Mr. Reid is President of Kentucky Downs Partners, LLC ("KDP"). KDP's principal business is
the ownership of a controlling interest in a thoroughbred horse racing track in Franklin, Kentucky. Prior to forming KDP in 2007, Mr. Reid served as President of R. Reid
Investments Inc., a private investment banking firm which exclusively served companies engaged in the energy industry. Mr. Reid holds a Bachelor of Arts degree from Oklahoma State
University and a Master of Business Administration degree from the Wharton School of the University of Pennsylvania.

Shelby E. Odellwas elected as a director of our general partner in September 2005 and serves as a member of our audit committee of the
board of directors of our general partner. Mr. Odell has served as a director of the general partner of Hiland Holdings GP, LP since September 2006, and serves as a member of the
audit committee of the board of directors of Hiland Holdings GP, LP's general partner. Mr. Odell has 40 years of experience in the petroleum business, including marketing,
distribution,
acquisitions, innovation of new asset opportunities, and management. From 1974 to 2000, Mr. Odell held several positions with Koch Industries. He retired in 2000 as President of Koch
Hydrocarbon Company and Sr. Vice President of Koch Industries. Prior to joining Koch, Mr. Odell advanced through several positions with Phillips Petroleum Company. He is a past member of the
Board of Directors of the Gas Processors Association and holds an Associate Degree in Accounting from Enid Business College.

John T. McNabb, IIwas elected as a director of our general partner in August 2006, and he serves as chairman of the conflicts committee
and as a member of the compensation committee of the board of directors of our general partner. Mr. McNabb is the founder of Growth Capital Partners, LP, a merchant banking firm that
provides financial advisory services to middle market companies throughout the United States, and he has served as the chairman of its board of directors since 1992. Mr. McNabb has also served
as a Principal of Southwest Mezzanine Investments, the investment affiliate of Growth Capital Partners, L.P, since 2001. From June 1990 to January 1992, Mr. McNabb was a Managing Director of
Bankers Trust Company, managing commercial banking, investment banking and financial advisory activities in the Southwest for Bankers Trust Company, and a director of BT Southwest, Inc., an
affiliate of Bankers Trust New York Corporation. Mr. McNabb currently serves as Chairman of board of directors of Willbros Group, Inc. He started his career, after serving in the U.S.
Air Force during the Vietnam conflict, with Mobil Oil in its exploration and production division. Mr. McNabb holds a Bachelor of Arts in History and a Masters of Business Administration from
Duke University.

Dr. David L. Borenwas elected as a director of our general partner in August 2006, and he serves as a member of the conflicts
committee of the board of directors of our general partner. Dr. Boren serves as President of the University of Oklahoma, a position he has held since November of 1994. Prior to becoming
President of the university, he served in the United States Senate representing Oklahoma from 1979 to 1994. During his service in the Senate he was the longest serving Chairman of the U.S. Select
Committee on Intelligence. From 1975 to 1979, Dr. Boren was Governor of Oklahoma. Before being elected Governor, he served 8 years in the Oklahoma House of Representatives. He engaged in
the private practice of law from 1969 to 1974. He also served as a professor of Political Sciences at Oklahoma Baptist University from 1970 to 1974. In 1986 Dr. Boren founded the Oklahoma
Foundation for Excellence, a private foundation which rewards and encourages excellence in public

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education.
He continues to serve as its Chairman. Dr. Boren received his BA degree from Yale University in 1963, his Master's Degree in Economics from Oxford University in 1965 as a Rhodes
Scholar and his Juris Doctorate Degree from the University of Oklahoma in 1968. He previously served as a director of ConocoPhillips Inc. and currently serves as a director of Texas
Instruments, AMR Corporation and Torchmark Corporation.

Board Committees

The board appoints committees to help carry out its duties. In particular, the board committees work on key issues in greater detail than would be possible at
full board meetings. Only
non-employee directors may serve on the audit, compensation and conflicts committees. Each committee has a written charter. The charters are posted on our Web site and are available free
of charge on request to our Secretary at the address given under "Contact Us".

The
table below shows the current membership of each board committee.

Name

Audit

Conflicts

CompensationMr. Hamm





CMr. Greenwood

CMr. Doherty

*Mr. Reid





*Mr. Odell

*Mr. McNabb, II



C

*Dr. Boren



*




Audit Committee

The audit committee of our general partner's board of directors is comprised of three non-employee members of the board. The committee is appointed by
the board of directors to assist the board in fulfilling its oversight responsibilities. Its primary responsibility is to monitor the quality, integrity and reliability of the financial reporting
process, review the adequacy of our systems of internal controls for financial reporting, legal compliance and ethics established by management and the board and review procedures for internal
auditing. Responsibilities also include the appointment, compensation, retention and oversight of the work of the independent registered public accounting firm engaged to prepare the audit report or
perform other audit, review or attestation services. The committee reviews proposed audit plans for the year and the coordination of these plans with the independent registered public accounting firm.
The committee also reviews, in conjunction with management and the independent registered public accounting firm, the financial statements and other information contained in our quarterly and annual
reports filed with the SEC to determine that the independent registered public accounting firm is satisfied with the disclosure and content of such financial statements and other information included
in the reports. The committee shall have authority to obtain advice and assistance from internal or external legal, financial and other advisors.

The
board has determined that all members of the committee are independent within the meaning of both the SEC rules and NASDAQ listing standards. The board has further determined that
all members are financially literate within the meaning of the NASDAQ standards and that Mr. Greenwood is an "audit committee financial expert" as defined in the SEC rules. In making these
determinations, the board reviewed information from each of these non-employee directors concerning all of their respective relationships with us and analyzed the materiality of those
relationships.

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Conflicts Committee

The conflicts committee of our general partner's board of directors is comprised of two non-employee members of the board. The committee is appointed
by the board of directors of our general partner to carry out the duties delegated by the board that relate to specific matters that the board believes may involve conflicts of interests between us
and our affiliates, on the one hand and us and any other group member, any partner or any assignee, on the other hand. The committee is composed solely of two independent directors who are not
unitholders, officers or employees of us or our general partner, officers, directors or employees of any affiliate or holders of any ownership interest in us other than our common units and who also
meet the independence and experience standards established by NASDAQ and any applicable laws and regulations.

The
committee shall advise the board on actions to be taken by us or matters related to us upon request of the board. The committee determines if the resolution of such conflicts of
interest is fair and reasonable to us. 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 to us or to our unitholders. In connection with the committee's resolution of any conflict of interest, the committee is authorized to consider the
relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest, any customary or accepted industry practices and any
customary or historical dealings with a particular person. The committee is also authorized to consider any applicable generally accepted accounting practices or principles and such additional factors
as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

With
respect to any contribution of assets to the Partnership in exchange for Partnership securities, the committee, in determining whether the appropriate number of Partnership
securities are being issued, may take into account, among other things, the fair market value of the assets, the liquidated and contingent liabilities assumed, the tax basis in the assets, the extent
to which tax-only allocations to the transferor will protect the existing partners of the Partnership against a low tax basis, and such other factors as the committee deems relevant under
the circumstances. The committee shall have authority to obtain advice and assistance from internal or external legal, financial and other advisors.

Compensation Committee

The compensation committee of our general partner's board of directors is comprised of three non-employee members of the board. The committee has
overall responsibility for approving and evaluating the general partner's director and officer compensation plans, policies and programs.

The
committee oversees the compensation for our senior executives, including their salary, bonus, and incentive and equity awards. The committee is responsible primarily for reviewing,
approving and reporting to the board on major compensation and benefits plans, policies and programs of the company; reviewing and evaluating the performance and approving the compensation of senior
executive officers; and overseeing management development programs, performance assessment of senior executives and succession planning. Other specific duties and responsibilities include: annually
reviewing and approving corporate goals and objectives relevant to the chief executive officer ("CEO") base compensation, incentive-compensation plans and equity-based plans; evaluating the CEO's
performance in light of those goals and objectives, and recommending to the board either as a committee or together with the other independent directors, the CEO's compensation levels based on this
evaluation; and producing the required annual report on executive compensation.

The
compensation committee has the sole authority to retain, amend the engagement with, and terminate any compensation consultant to be used to assist it in the evaluation of director,
CEO or officer compensation. The committee has sole authority to approve the consultant's fees and other retention terms and shall have authority to cause us to pay the fees and expenses of such
consultants.

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The
committee shall also have authority to obtain advice and assistance from internal or external legal, accounting or other advisors, to approve the fees and expenses of such outside advisors, and to
cause us to pay the fees and expenses of such outside advisors.

Report of the Audit Committee for the Year Ended December 31, 2007

Our management is responsible for our internal controls and our financial reporting process. Grant Thornton LLP, our Independent Registered Public
Accounting Firm for the year ended December 31, 2007, is responsible for performing an integrated audit of the effectiveness of internal control over financial reporting and an independent
audit of our consolidated financial statements in accordance with standards of the Public Company Accounting Oversight Board and to issue a report thereon. Our audit committee monitors and oversees
these processes. Our audit committee, made up of members of our general partner's Board of Directors, selects our independent registered public accounting firm.

Our
audit committee has reviewed and discussed our audited consolidated financial statements with our management and the independent registered public accounting firm. Our audit
committee has discussed with Grant Thornton LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended, "Communications with Audit Committees,"
including that firm's independence.

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

Code of Ethics

Our general partner has adopted a Financial Officers Code of Ethics applicable to the Chief Executive Officer and the Chief Financial Officer, Controller and all
other senior financial and accounting officers (the "Senior Financial Officers") with regard to Partnership-related activities. This Code of
Ethics contains the policies that relate to the legal and ethical standards of conduct that the Senior Financial Officers of our general partner are expected to comply with while carrying out their
duties and responsibilities on behalf of the Company. The Code of Ethics also incorporates expectations of Senior Financial Officers that enable us to provide accurate and timely disclosure in our
filings with the SEC and other public communications. The Code of Ethics is publicly available on our website under the "Governance" section (at www.hilandpartners.com) and is also available free of
charge on request to the Secretary at the address given under "Contact Us."

Section 16(a) Beneficial Ownership Reporting Compliance

Based upon our records, except as set forth below, we believe that during 2007 all reporting persons complied with the Section 16(a) filing requirements
applicable to them. Due to an administrative error, a Form 4 was filed late on behalf of Shelby Odell on August 15, 2007.

Compensation Committee Interlocks and Insider Participation

Harold Hamm serves as the chairman of our Compensation Committee. Mr. Hamm controls CLR, and the required disclosure concerning related party transactions
involving Mr. Hamm, CLR and us are set forth below. Other members of the compensation committee include Mr. John T. McNabb, II and Mr. Rayford T. Reid.

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Item 11.    Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

Compensation Objectives and Philosophy

The executive compensation program of our general partner is designed to enable our general partner to execute our business objectives by attracting, retaining,
and motivating the highest quality of executive talent and by rewarding superior performance. Performance management focuses on building competencies required for our business and achieving the
highest level of contribution from each employee. Our compensation and benefits policies and practices are designed to motivate and reward officers and employees to achieve goals and objectives that
are expected to lead to long-term enhancement of unitholder value, provide total compensation that is competitive within the market place and align individual compensation with competency
and contribution so that performance, tied to measurable objectives and results, will be rewarded appropriately. We identify our marketplace as the following publicly traded midstream and pipeline
master limited partnerships within our peer group: Atlas Pipeline Partners, LP, Copano Energy, LLC, Crosstex Energy, LP, DCP Midstream Partners, LP, Global
Partners, LP, MarkWest Energy Partners, LP, Regency Energy Partners, LP, SemGroup Energy Partners, LP and TransMontaigne Partners, LP. The compensation committee,
established in May 2005, believes this definition of our marketplace along with third-party industry compensation surveys provides a good benchmark for analyzing the competitiveness of our executive
compensation program.

In
addition to base salary, executive officers are compensated on a performance-oriented basis through the use of incentive compensation linking both annual and longer-term
results. The annual incentive bonus permits team and individual performance to be recognized and is based, in part, on an evaluation of the contribution made by the officer to our performance. Equity
compensation awards are included in the compensation program to reward executive officers for long-term strategic actions that increase our value and thus unitholder value and to link a
significant amount of an executive's current and potential future net worth to our success. This use of equity compensation directly relates a portion of each executive officer's long-term
remuneration to our unit price, and therefore aligns the executive's compensation with the interests of other unitholders. The discretionary granting of unit options, as well as the use of restricted
and phantom units, is used to (1) recognize promotions of executives into positions of significant responsibilities; (2) recognize significant accomplishments of executives, particularly
as the accomplishments impact growth, profits and/or competitive positioning; and (3) attract and retain high level executive talent.

Oversight of Executive Compensation Program

The compensation committee of our general partner administers our executive officer compensation program. The compensation committee is primarily responsible for
reviewing, approving and reporting to the board on major compensation and benefits plans, policies and programs of the Partnership; reviewing and evaluating the performance and approving the
compensation of senior executive officers; and overseeing management development programs, performance assessment of senior executives and succession planning. Other specific duties and
responsibilities include: annually reviewing and approving corporate goals and objectives relevant to the chief executive officer ("CEO") base compensation, incentive-compensation plans and
equity-based plans; evaluating the CEO's performance in light of
those goals and objectives, and recommending to the board, either as a committee or together with the other independent directors, the CEO's compensation levels based on this evaluation; and producing
the required annual report on executive compensation. The compensation committee annually evaluates the effectiveness of the executive compensation program in meeting its objectives.

The
CEO submits annual base compensation, incentive-compensation and equity-based compensation recommendations of senior executive officers below the CEO to the compensation

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committee
based on each executive's contribution to our performance and each executive's responsibilities and management abilities. The compensation committee evaluates compensation with reference to
our financial and operating performance, distribution performance, relative unitholder total return for the prior fiscal year, competitive compensation data of executives in our marketplace and each
executive's individual performance evaluation, length of service with the company and previous work experience. The compensation committee annually advises the board on the compensation to be paid to
the executive officers and approves the compensation for executive officers.

The
compensation committee has the sole authority to retain, amend the engagement with, and terminate any compensation consultant to be used to assist it in the evaluation of director,
CEO and executive officer compensation, as appropriate. The committee has sole authority to approve the consultant's fees and other retention terms and shall have authority to cause us to pay the fees
and expenses of such consultants. The committee shall also have authority to obtain advice and assistance from internal or external legal, accounting or other advisors, to approve the fees and
expenses of such outside advisors, and to cause us to pay the fees and expenses of such outside advisors. The compensation committee formed a search committee and engaged Heidrick & Struggles
to identify potential new CEO candidates; but otherwise did not engage a compensation consultant to assist it in determining executive compensation for our fiscal year ending December 31, 2007.

Elements of Compensation

Our general partner's executive compensation program currently consists of the following elements:



Base Salaries

Base salary for each executive officer is determined annually by an assessment of our overall financial and operating performance, each executive officer's
performance evaluation, changes in executive officer responsibilities and relevant marketplace data. While many aspects of performance can be measured in financial terms, the compensation committee
also evaluates senior management in areas of performance that are more subjective. These areas include the development and execution of strategic plans, the exercise of leadership in the development
of management and other employees, innovation and improvement in our business activities, as well as the executive's involvement in industry groups and in the communities that we serve. Our general
partner seeks to compensate executives for their performance throughout the year with annual base salaries that are fair and competitive within our marketplace. Our general partner believes that
executive base salaries should be targeted near the median of the range of salaries for executives in similar positions and with similar responsibilities in our marketplace and adjusted for financial
and operating performance and each executive's performance evaluation, length of service with the company and previous work experience. Individual salaries are generally established in alignment with
these considerations to ensure the attraction, development and retention of superior talent, as well as in relation to individual executive performance. Base salaries are reviewed annually to ensure
continuing consistency with market levels and our level of financial performance during the previous fiscal year. Future adjustments to base salaries and salary ranges will reflect average movement in
the competitive market as well as individual performance.

Base
salaries in 2007 for the Chief Financial Officer ("CFO") and the Vice President of Operations and Engineering were set based on (1) the latest available financial results of
operations; (2) each executive's performance evaluation; and (3) the comparable base salaries of executives within our marketplace and our most recent third-party industry compensation
survey. The CFO's annual base

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salary
was $225,000 for the period of November 2006 through October 2007. The CFO's current annual base salary, established at the compensation committee's meeting in November 2007, is $255,000 and
approximates the median annual base salaries within our marketplace for 2006 and our most recent third-party industry compensation survey for his position. The Vice President of Operations and
Engineering's annual base salary was $160,000 for the period of March 2006 through February 2007. The Vice President of Operations and Engineering's current annual base salary, established at the
compensation committee's meeting in March 2007, is $190,000 and approximates the median annual base salary within our most recent third-party industry compensation survey for his position. The annual
base salary for our Vice President of Operations and Engineering will be addressed at the compensation committee meeting to be held in March 2008. The CEO's annual base salary was $260,000 for the
period of June 2007 through October 2007 based on previous work experience. The CEO's current annual base salary, established at the compensation committee's meeting in November 2007, is $290,000 and
approximates 83% of the median annual base salary within our marketplace for 2006 for his position. The CEO's current annual base salary was set based on his initial performance evaluation. Also, in
January 2008, an annual base salary of $200,000 was established for a new Vice President of Business Development to join our team in early 2008, primarily determined by the comparable base salaries of
similar executives within our marketplace.

Annual Incentive Cash Bonus

Annual incentive cash bonuses are intended to compensate executive officers for achieving our annual financial goals and for achieving measurable individual
annual performance objectives. Annual cash bonuses are 100% discretionary and are determined by our financial and operating performance relative to financial goals, distribution performance, relative
unitholder total return for the prior fiscal year, the executive's performance evaluation and the median incentive cash bonuses of executive officers within our marketplace. The compensation committee
approves the annual incentive award, if any, for the CEO, and for each officer below the CEO level based on the CEO's recommendations. EBITDA, natural gas sales, NGL sales and distributions per unit
increased 79%, 42%, 70% and 34%, respectively in 2006 as compared to 2005. Our unitholder total return for 2006 was approximately 56% compared to the median for our marketplace of approximately 38%.
Discretionary cash bonuses were awarded in March 2007 to our past CEO, CFO, and the Vice President of Operations and Engineering in the amounts of $150,000, $123,750 and $88,000, respectively,
representing approximately 55%, 124% and 69% of the median incentive cash bonuses for such positions within our marketplace for 2005. The past Vice President of Business Development received a
discretionary cash bonus of $51,000 in March 2007. Discretionary cash bonuses for our three named executive officers and our past Vice President of Business Development are to be addressed at the
compensation committee meeting to be held in March 2008.

Long-Term Incentive Compensation

Our general partner adopted the Hiland Partners, LP Long-Term Incentive Plan for the employees and directors of our general partner and the
employees of its affiliates. The compensation plan is administered by the compensation committee of our general partner's board of directors and 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.

The
long-term incentive compensation plan is designed to reward executives and other key employees for the attainment of financial goals and other performance objectives
approved annually by the compensation committee and to encourage responsible and profitable growth while taking into account non-routine factors that may be integral to our success.
Long-term incentive compensation in the form of equity grants of our common units, such as incentive unit option grants and grants of

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restricted
units and phantom units, are used to incent performance that leads to enhanced unitholder value, encourage retention and closely align the executive's interests with unitholders'
long-term interests. Equity grants provide a vital link between the long-term results achieved for our unitholders and the rewards provided to executives and other key
employees. The equity grants we adopted upon the formation of our long-term incentive compensation plan were designed to be comparable with long-term incentive plans of other
midstream and pipeline master limited partnerships.

Under
the unit option grant agreement, granted options of common units vest and become exercisable in one-third increments on the anniversary of the grant date over three
years. Vested unit options are exercisable within the option's contractual life of ten years after the grant date. Restricted units vest in quarterly increments over a four-year period
from the date of issuance. Phantom units vest in increments and over a period of time as determined by the compensation committee. Unvested unit options, restricted units and phantom units generally
become fully vested upon the disability, death or termination other than for cause of the holder or a change of control of our general partner. If the holder ceases to be an officer or employee of our
general partner for any other reason, his or her unvested unit options, restricted units or phantom units are forfeited. Unit option awards are less attractive than restricted units or phantom units
to the recipient because the fair value of the unit option at the grant date is generally less than the fair value of the restricted unit or phantom unit at the grant date, which bears no cost to the
recipient.

The
size of the unit option, restricted unit and phantom unit grants is determined relative to our size and our market, employee qualifications and position, as well as master limited
partnership peer group data. All grants to executive officers require board approval. Neither our general partner nor the compensation committee has a program, plan or practice to time options or
grants to its executives in coordination with the release of material nonpublic information. Any unit options, restricted units or
phantom units grants made to non-executive employees typically will occur concurrently with grants to named executive officers. All unit options are granted at the fair market value of our
units on the date of grant. The compensation committee determines the aggregate amounts, terms and timing of unit option, restricted unit and phantom unit awards. The number of units covered by each
award reflects the executive's level of responsibility along with past and anticipated future contributions to us. Initially, based on comparable options granted to executives of similar midstream and
pipeline master limited partnerships at their respective initial public offerings, the past CEO recommended to the chairman of the board the number of options to be granted to executive officers and
key employees at our initial public offering in February 2005. In November 2005, the compensation committee approved 15,000 and 13,000 unit options to be granted to an additional Vice President of
Operations and Engineering and a Vice President of Business Development, respectively, on their hire dates in early 2006. In November 2006, the compensation committee approved 3,000 restricted units
to be granted to the Vice President of Operations and Engineering. In June 2007, the compensation committee approved 10,000 phantom units to be granted to our current CEO. In November 2007, the
compensation committee approved 5,000 phantom units to be granted to the CFO, 5,000 phantom units to be granted to the Vice President of Operations and Engineering and 21,825 phantom units to be
granted to key employees. In December 2007, our CEO awarded 1,000 phantom units to a key employee. The compensation committee also approved 7,500 phantom units to be granted to the Vice President of
Business Development upon his appointment in February 2008.

Employment, Change in Control and Salary Continuation Agreements

No employment agreements exist with any employee of our general partner.

Change
in control agreements exist only with respect to all unexercised unit options, restricted units and phantom units held by all employees and directors of our general partner which
in the event of any of the following change of control events become fully vested and exercisable. A change of control generally shall be deemed to occur upon the occurrence of one or more of the
following events:

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(i) any
sale, lease, exchange or other transfer or disposition of all or substantially all of the assets of the Partnership to any party not affiliated with the Partnership and/or any of our
affiliates; (ii) the consolidation, reorganization, merger or other transaction pursuant to which more than 50% of the combined voting power of the outstanding equity interests in the
Partnership cease to be directly or indirectly owned by our current majority owner group or their affiliate; or (iii) our general partner ceases to be the general partner of the Partnership. If
a qualifying change in control event had occurred as of December 31, 2007, the estimated value of payments and benefits that would inure to the benefit of the executive officers and directors
as a group would have been approximately $2.4 million.

Our
general partner currently has no salary continuation agreement, or agreement having similar effect, in place with any employee of our general partner other than the change in control
agreements described above.

Hiland Holdings GP, LP Class B Common Units

In connection with our initial public offering on February 15, 2005, our general partner issued Class B member interests in our general partner to
our past CEO and CFO as compensation for services to be rendered exclusively for the benefit of our general partner. In addition, in connection with the initial public offering of Hiland
Holdings GP, LP on September 25, 2006, Class B common units in Hiland Holdings, GP, LP, who, at that time, became a majority common unitholder of Hiland
Partners, LP, were issued to our past CEO and CFO as consideration for their unvested Class B member interests in our general partner. The Hiland Holdings GP, LP
Class B common units have substantially identical rights as Hiland Holdings GP, LP common units and, upon vesting, become convertible at the election of the holder into common
units. Prior to conversion, the Class B common units are non-transferable. The Class B common units vested in equal increments on February 15, 2007 and
February 15, 2008. In February and April 2007, our past CEO elected to convert his vested Class B common units to common units. In April 2007, our past CEO resigned and his unvested
Class B common units in Hiland Holdings, GP, LP, were forfeited and transferred to the Hiland Holdings GP, LP's contributing parties on a pro rata basis based on
their vested ownership of Hiland Partners GP, LLC immediately prior to the contribution of those interests in connection with their formation. In February 2008, our CFO elected to
convert his Class B common units to common units.

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Summary Compensation Table

The following table sets forth information regarding compensation earned by our CEO, our CFO and three other most highly compensated executive officers employed
in 2007 and 2006:

SUMMARY COMPENSATION TABLE

|                                                                         |  |           |  | Annual Compensation |                 | Long-Term Compensation |    |               
|------------------------------------------------------------------------ |  | --------- |  | ------------------- | --------------- | ---------------------- | -- | --------------
|
|Joseph GriffinPresident and Chief Executive Officer                     |  | 2007      |  | $                   | 137,494         |                        | $  | 40,000        
|Randy MoederPast President and Chief Executive Officer                  |  | 2007
2006 |  | $$                  | 101,021
231,058 |                        | $$ | 130,000
85,000
|Ken MaplesVice President-Finance, Secretary and Chief Financial Officer |  | 2007
2006 |  | $$                  | 218,318
192,490 |                        | $$ | 113,750
55,000
|Robert ShainVice President of Operations and Engineering                |  | 2007
2006 |  | $$                  | 184,961
126,151 |                        | $$ | 88,000
40,000 
|Ron HillPast Vice President of Business Development                     |  | 2007
2006 |  | $$                  | 166,211
147,692 |                        | $$ | 51,000
      
|Clint DutyPast Vice President of Operations and Engineering             |  | 2006      |  | $                   | 46,577          |                        | $  |              

---

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Grants of Plan Based Awards

The following table provides information regarding unit options and restricted and phantom units awarded in 2007 and 2006:

GRANTS OF PLAN BASED AWARDS

|Name        |  | Grant Date |  | All Other
Unit Awards:
Number of
Units (#) |  | Base Price
of Unit
Awards
($/Unit) |       | All Other
Option
Awards:
Number of
Securities
Underlying
Options (#) |   | Exercise or
Base Price
of Option
Awards
($/Unit) |   | Grant Date
Fair Value
of Option
Awards
($/Unit)
|----------- |  | ---------- |  | ------------------------------------------ |  | ---------------------------------- | ----- | -------------------------------------------------------------------- | - | ------------------------------------------------ | - | -----------------------------------------------
|Mr. Griffin |  | 6/19/2007  |  | 10,000                                     |  | $                                  | 54.50 |                                                                      |  |                                                  |  |                                                
|Mr. Maples  |  | 11/6/2007  |  | 5,000                                      |  | $                                  | 48.80 |                                                                      |  |                                                  |  |                                                
|Mr. Shain   |  | 11/6/2007  |  | 5,000                                      |  | $                                  | 48.80 |                                                                      |  |                                                  |  |                                                
|Mr. Hill    |  | 11/6/2007  |  | 825                                        |  | $                                  | 48.80 |                                                                      |  |                                                  |  |                                                

Mr. Griffin's
was awarded 10,000 phantom units in June 2007. Mr. Griffin's phantom units vest in four year annual increments and periodic distributions on his unvested
units are held in trust by our general partner until the units vest. Messrs. Maples, Shain and Hill were awarded 5,000, 5,000 and 825 phantom units, respectively, in November 2007.
Messrs. Maples, Shain and Hill's phantom units also vest in four year annual increments, but do not accumulate distributions on the unvested units.

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Outstanding Equity Awards at Fiscal Year-End Table

The following table provides information regarding outstanding awards that have been granted, but the ultimate outcomes of which have not been realized:

OUTSTANDING EQUITY AWARDS AS FISCAL YEAR-END

|Name           |  | Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable |  | Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable |  | Option
Exercise
Price ($) |       | Option
Expiration
Date |          | Number of
Restricted
and Phantom
Units That
Have Not
Vested (#) |        | Market
Value of
Units and
Options That
Have Not
Vested ($)
|-------------- |  | ------------------------------------------------------------------- |  | --------------------------------------------------------------------- |  | ------------------------- | ----- | ---------------------- | -------- | --------------------------------------------------------------- | ------ | ----------------------------------------------------------
|Mr. Griffin(1) |  |                                                                    |  |                                                                      |  | $                         |      |                        |         |                                                                 | 10,000 |                                                           
|Mr. Maples(2)  |  | 6,667                                                               |  | 6,666                                                                 |  | $                         | 22.50 |                        | 02/10/15 |                                                                 | 5,000  |                                                           
|Mr. Shain(3)   |  | 5,000                                                               |  | 10,000                                                                |  | $                         | 40.70 |                        | 03/20/16 |                                                                 | 7,250  |                                                           
|Mr. Hill(4)    |  | 4,333                                                               |  | 4,334                                                                 |  | $                         | 38.72 |                        | 01/05/16 |                                                                 | 825    |                                                           

---

Option Exercises and Units Vested Table

The table presented below provides information of the values realized upon the exercise of options during 2007 and 2006 based on the difference between the market
price of the underlying units at exercise and the exercise or base price of the unit options:

OPTION EXERCISES AND UNITS VESTED

Option Awards

Unit AwardsName

Number
of Units
Acquired on
Exercise (#)

Value
Realized
Upon
Exercise ($)

Number
of Units
Acquired on
Vesting (#)

Value
Realized
Upon
Vesting ($)Mr. Moeder

12,566

$
418,843



$
Mr. Shain



$


750

$
36,024Mr. Hill

4,333

$
70,462



$



No
restricted units granted to executive officers vested in 2006.

Director Compensation

Generally, Mr. Harold Hamm, the chairman of the board of directors of our general partner and a non-employee director, receives no form of
director compensation whatsoever. Mr. Hamm did,

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however,
serve on a CEO search committee formed to secure a replacement for our past CEO, who resigned in April 2007. Mr. Griffin, our CEO and Mr. Maples our CFO, who are employees of
our general partner, are also non-compensated members of the board of directors of our general partner. Mr. Moeder, our past CEO was also a non-compensated member of the
board of directors of our general partner. The table below shows the total compensation paid in 2007 to each of our current non-employee directors:

DIRECTOR COMPENSATION

|Name                 |  | Annual Base Fee(1) ($) |        | Committee
Fees ($) |   | Restricted Unit
Awards(2) ($) |  | Restricted Unit
Distributions(3) ($) |        | Total ($)
|-------------------- |  | ---------------------- | ------ | ------------------ | - | ----------------------------- |  | ------------------------------------ | ------ | ---------
|Harold Hamm          |  | $                      |       |                    | $ | 10,500                        |  | $                                    |       |          
|Michael L. Greenwood |  | $                      | 31,000 |                    | $ | 9,000                         |  | $                                    | 52,460 |          
|Edward D. Doherty    |  | $                      | 31,000 |                    | $ | 4,000                         |  | $                                    | 52,460 |          
|Rayford T. Reid      |  | $                      | 31,000 |                    | $ | 13,500                        |  | $                                    | 52,460 |          
|Shelby E. Odell      |  | $                      | 31,000 |                    | $ | 4,000                         |  | $                                    | 49,420 |          
|John T. McNabb, II   |  | $                      | 31,000 |                    | $ | 20,500                        |  | $                                    | 52,460 |          
|Dr. David L. Boren   |  | $                      | 31,000 |                    | $ | 15,000                        |  | $                                    | 52,460 |          

---

No
additional remuneration is paid to officers of our general partner who also serve as directors. Our independent directors receive (a) a $25,000 annual cash retainer fee,
(b) $1,500 for each regularly scheduled meeting attended, (c) $750 for each special meeting attended and (d) 2,000 restricted units upon becoming a director and 1,000 restricted
units on each anniversary date of becoming a director and (e) during 2007, CEO search committee fees to secure a replacement for our CEO who resigned in April 2007. The restricted units vest in
quarterly increments on the anniversary of the grant date over a period of four years. In addition to the foregoing, each director who serves on a committee receives $1,000 for each committee meeting
attended, the chairman of our audit committee receives an annual retainer of $5,000 and the chairmen of our other committees receive an annual retainer of $2,500. In addition, each independent
director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified for his
actions associated with being a director to the fullest extent permitted under Delaware law.

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

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reimbursed
to our general partner for compensation or expenses incurred on our behalf. CLR currently provides us with certain general and administration services. For a description of these services,
please read "Certain Relationships and Related Party TransactionsAgreements with Harold Hamm and His AffiliatesOmnibus AgreementServices." In the omnibus
agreement, CLR agreed to continue to provide these services to us for two years after our initial public offering, at the lower of CLR's cost to provide the services or $50,000 per year. During the
third quarter of 2006, we hired a director of information technology and a director of human resources and transitioned these services away from CLR. The remainder of general and administration
services provided by CLR under this agreement expired on February 15, 2007.

Long-Term Incentive Plan

Our general partner has adopted the Hiland Partners Long-Term Incentive Plan for employees and directors of our general partner and employees of its
affiliates. The plan is intended to promote our interests and the interests of our general partner by providing to employees and directors of our general partner and its affiliates incentive
compensation awards for superior performance that are based on units. The plan is also contemplated to enhance the ability of our general partner, its affiliates or us to attract and retain the
services of individuals who are essential for our growth and profitability and to encourage them to devote their best efforts to advancing our business. The long-term incentive plan
currently permits an aggregate of 680,000 common units to be issued with respect to unit options, restricted units and phantom units granted under the plan. No more than 225,000 of the 680,000 common
units may be issued with respect to vested restricted or phantom units. The plan is administered by the compensation committee of our general partner's board of directors. The plan will continue in
effect until the earliest of (i) the date determined by the board of directors of our general partner; (ii) the date that common units are no longer available for payment of awards under
the plan; or (iii) the tenth anniversary of the plan.

Our
general partner's board of directors or compensation committee may, in their discretion, terminate, suspend or discontinue the long-term incentive plan at any time with
respect to any units for which a grant has not yet been made. Our general partner's board of directors or its compensation committee also has the right to alter or amend the long-term
incentive
plan or any part of the plan from time to time, including increasing the number of units that may be granted, subject to unitholder approval if required by the exchange upon which the common units are
listed at that time. No change in any outstanding grant may be made, however, that would materially impair the rights of the participant without the consent of the participant.

Restricted Units and Phantom Units.A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the
grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the
discretion of the compensation committee, cash equivalent to the value of a common unit. The compensation committee may make grants of restricted units and phantom units under the plan to employees
and directors containing such terms as the compensation committee shall determine under the plan, including the period over which restricted units and phantom units granted will vest. The committee
may, in its discretion, base its determination on the grantee's period of service or upon the achievement of specified financial objectives. In addition, the restricted and phantom units will vest
upon a change of control of us or our general partner, subject to additional or contrary provisions in the award agreement.

If
a grantee's employment or membership on the board of directors terminates for any reason, the grantee's restricted units and phantom units will be automatically forfeited unless, and
to the extent, the compensation committee provides otherwise or unless otherwise provided in a written employment agreement between the grantee and our general partner or its affiliates. Common units
to be delivered with respect to these awards may be common units acquired by our general partner in the open

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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 of our operating company. Unless otherwise provided in an award agreement, unit options may be exercised only by the participant during his
lifetime or by the person to whom the participant's right will pass by will or the laws of descent and distribution. If a grantee's employment or membership on the board of directors terminates for
any reason, the grantee's unvested options will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise or unless otherwise provided in a written employment
agreement or the option agreement between the grantee and our general partner or its affiliates. If the exercise of an option is to be settled in common units rather than cash, the general partner
will acquire common units in the open market or directly from us or any other person or use common units already owned by our general partner or any combination of the foregoing. The general partner
will be entitled to reimbursement by us for the difference between the cost incurred by it in acquiring these common units and the proceeds it receives from a grantee at the time of exercise. Thus,
the cost of the unit options above the proceeds from grantees will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will
increase, and our general partner will pay us the proceeds it received from the grantee upon exercise of the unit option. The plan has been designed to furnish additional compensation to employees and
directors and to align their economic interests with those of common unitholders.

Unit Option Grant Agreement.As of January 1, 2008, we have outstanding unit options to officers, directors and
employees of our general partner to purchase an aggregate of 75,041 common units with a weighted average exercise price of $31.11. Please see the option grant table above for a description of grants
made to named executive officers during 2006 and 2005. No unit options were granted in 2007. Under the unit option grant agreements, the options vest and may be exercised in one third increments on
the anniversary of the grant date over a period of three years. In addition, the unit options will vest and become exercisable, subject to certain conditions, upon the occurrence of any of the
following



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In
February 2007, one third of the remaining 123,000 unit options granted on February 10, 2005 vested and 1,899 units granted to our past CEO vested in April 2007 as provided for
in his termination agreement. Of the 42,899 units that vested, 38,327 were exercised in 2007, resulting in cash contributions to us of $0.9 million. During 2007, 9,767 unit options granted on
February 10, 2005 were forfeited. The remaining 29,334 unit options granted on February 10, 2005 vested on February 10, 2008 and on January 5, 2008, 4,333 unit options
granted on January 5, 2006 also vested. Of the total 33,667 units vested 22,039 were exercised in February 2008 resulting in cash contributions to us of $0.6 million.

Report of the Compensation Committee

The compensation committee of the Board of Directors of Hiland Partners GP, LLC administers the executive compensation program of Hiland
Partners, LP. The compensation committee is primarily responsible for reviewing, approving and reporting to the Board of Directors of Hiland Partners GP, LLC on major compensation
and benefits plans, policies and programs of Hiland Partners, LP; reviewing and evaluating the performance and approving the compensation of senior executive officers; and overseeing management
development programs, performance assessment of senior executives and succession planning. Other specific duties and responsibilities include: annually reviewing and approving corporate goals and
objectives relevant to the CEO base compensation, incentive-compensation plans and equity-based plans; evaluating the CEO's performance in light of those goals and objectives, and recommending to the
Board of Directors, either as a committee or together with the other independent directors, the CEO's compensation levels based on this evaluation; and producing the required annual report on
executive compensation. The compensation committee annually evaluates the effectiveness of the executive compensation program in meeting its objectives.

As
required by applicable regulations of the Securities and Exchange Commission, the compensation committee reviewed and discussed with management the compensation discussion and
analysis contained in this Annual Report on Form 10-K. Based on the reviews and discussions referred to above, the compensation committee recommended to the Board of Directors of
Hiland Partners GP, LLC that the compensation discussion and analysis be included in the Annual Report on Form 10-K for the year ended December 31, 2007 for
filing with the SEC.

Respectively
submitted on March 7, 2008 by the members of the compensation committee of the Board of Directors of Hiland Partners GP, LLC:

Harold
Hamm, Chairman
John T. McNabb, II
Rayford T. Reid

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

Beneficial Ownership Of Hiland Partners, LP.The following table sets forth the beneficial ownership of our units as
of March 7, 2008 held by each person who beneficially owned more than 5% or more of the then outstanding units and all of the directors, named executive officers, and directors and executive
officers as a group of our general partner.

|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)(3)                            |  | 1,301,471                       |  | 24.9                                          | % | 4,080,000                             |  | 100.0                                               | % | 57.8                                         | %
|Joseph L. Griffin(1)                            |  |                                |  |                                              |   |                                      |  |                                                    |   |                                             |  
|Ken Maples(1)(2)(4)                             |  | 13,333                          |  |                                              |   |                                      |  |                                                    |   |                                             |  
|Robert Shain(1)(5)                              |  | 13,000                          |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|Matthew S. Harrison(1)                          |  |                                |  |                                              |   |                                      |  |                                                    |   |                                             |  
|Michael L. Greenwood(1)(2)(6)                   |  | 12,291                          |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|Edward D. Doherty(1)(2)(6)                      |  | 4,000                           |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|Rayford T. Reid(1)(2)(6)                        |  | 10,818                          |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|Shelby E. Odell(1)(2)(6)                        |  | 4,000                           |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|John T. McNabb, II(1)(7)                        |  | 3,000                           |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|Dr. David L. Boren(1)(7)                        |  | 3,000                           |  | *                                             |   |                                      |  |                                                    |   | *                                            |  
|Kayne Anderson Capital Advisors, L.P.(8)        |  | 377,292                         |  | 7.2                                           | % |                                      |  |                                                    |   | 4.1                                          | %
|Swank Capital, LLC(9)                           |  | 527,527                         |  | 10.1                                          | % |                                      |  |                                                    |   | 5.7                                          | %
|All directors and executive officers as a group |  | 1,365,247                       |  | 26.1                                          | % | 4,080,000                             |  | 100.0                                               | % | 58.5                                         | %

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Beneficial Ownership of Hiland Holdings GP, LP.The following table sets forth the beneficial
ownership of units of Hiland Holdings GP, LP as of March 7, 2008 held by each person who beneficially owned more than 5% or more of the then outstanding units and all of the
directors, named executive officers, and directors and executive officers as a group of Hiland Holdings GP, LP.

Name of Beneficial Owner(1)

Common Units
Beneficially
Owned

Percentage of
Common Units
Beneficially
OwnedHarold Hamm(2)

7,732,884

35.8%Harold Hamm DST Trust(2)

3,225,650

14.9%Harold Hamm HJ Trust(2)

2,150,218

9.9%Michael L. Greenwood(3)

3,000

*Edward D. Doherty(3)

3,500

*Rayford T. Reid(3)

28,000

*Shelby E. Odell(3)

8,000

*Dr. Cheryl L. Evans(3)

3,500

*Dr. Bobby B. Lyle(3)

53,000

*All directors and executive officers as a group

7,831,884

36.2%




Beneficial Ownership of Our General Partner Interest.Hiland Holdings GP, LP owns all of our 2%
general partner interest, all of our incentive distributions rights, 1,301,471 of our common units and 4,080,000 of our subordinated units.

Item 13.    Certain Relationships and Related Transactions and Director Independence

For a discussion of director independence, see Item 10. "Directors and Executive Officers of the Registrant."

Harold
Hamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust own 60.6% of Hiland Holdings GP, LP, who owns all of our 2% general partner interest, all of our
incentive distributions rights, 1,301,471 of our common units and 4,080,000 of our subordinated units.

Distributions and Payments to Our General Partner and its Affiliates

Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are
reimbursed for all expenses that they

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incur
on our behalf, including general and administrative expenses, salaries and benefits for all of our employees and other corporate overhead. Our general partner determines the amount of these
expenses. In the omnibus agreement, CLR agreed to continue to provide certain general and administrative services to us for two years after our initial public offering, at the lower of CLR's cost to
provide the services or $50,000 per year. During the third quarter of 2006, we hired a director of information technology and a director of human resources and transitioned these services away from
CLR. The remainder of general and administration services provided by CLR under this agreement expired on February 15, 2007. Please read "Omnibus AgreementServices"
below. In addition, our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the
amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.

Omnibus Agreement

Upon the closing of our initial public offering, we entered into an omnibus agreement with CLR, Hiland Partners, LLC, Harold Hamm, Continental Gas
Holdings, Inc. and our general partner that addressed the following matters:



Non-Competition

Harold Hamm will not, and will cause his affiliates not to engage in, whether by acquisition, construction, investment in debt or equity interests of any person
or otherwise, the business of gathering, treating, processing and transportation of natural gas in North America, the transportation and fractionation of NGLs in North America, and constructing,
buying or selling any assets related to the foregoing businesses. This restriction does not apply to:



95

---





These
non-competition obligations will terminate on the first to occur of the following events:



Indemnification

CLR, Hiland Partners, LLC and Continental Gas Holdings, Inc. agreed to indemnify us for all federal, state and local income tax liabilities
attributable to the operation of the assets contributed by such entities to us prior to the closing of our initial public offering. In addition, CLR agreed to indemnify us for a period of five years
from the closing date of our initial public offering for liabilities associated with oil and gas properties conveyed by CGI to CLR by dividend.

Contracts with CLR

Compression Services Agreement

In connection with our initial public offering, we entered into a four-year compression services agreement with CLR as described under "Management's
Discussion and Analysis of Financial Condition and Results of OperationsOur ContractsCompression Services Agreement." For the years ended December 31, 2007 we received
revenues of $4.8 million from CLR under this arrangement.

Gas Purchase Contracts

We purchase natural gas and NGLs from CLR and its affiliates. We purchased natural gas and NGLs from CLR and its affiliates in the amount of approximately
$60.1 million for the years ended December 31, 2007.

Badlands Purchase Contract

On November 8, 2005, we entered into a new 15-year definitive gas purchase agreement with CLR under which we will gather, treat and process
additional natural gas, which is produced as a by-product of CLR's secondary oil recovery operations, in the areas specified by the contract. In return, we will receive 50% of the proceeds
attributable to residue gas and natural gas liquids sales as well as certain fixed fees associated with gathering and treating the natural gas, including a $0.60 per Mcf fee for the first 36 Bcf of
natural gas gathered. The board of directors, as well as the conflicts committee of the board of directors, of our general partner have approved the agreement.

In
order to fulfill our obligations under the agreement, we expanded our Badlands gas gathering system and processing plant located in Bowman County, North Dakota. This expansion project
included the construction of a 40,000 Mcf/d nitrogen rejection plant, which became operational in the third quarter of 2007, and the expansion of our existing Badlands field-gathering infrastructure.

Other Agreements

Historically, our predecessor and Hiland Partners, LLC have contracted for down hole well services, fluid supply and oil field services from businesses in
which Harold Hamm and members of his

96

---



family
have historically owned equity interests. Mr. Hamm and members of his family sold these businesses to Complete Production Services, Inc. in October 2004. Mr. Hamm is
currently a director and stockholder of Complete Production Services. Payments made for these services by our predecessor and Hiland Partners, LLC on a combined basis were $305,000 during the
year ended December 31, 2007. We have continued to obtain services from these companies following the completion of our initial public offering. Based on various bids received by our general
partner from unaffiliated third parties, our general partner believes that amounts paid for these services are comparable to amounts which would be charged by an unaffiliated third party.

We
lease office space under operating leases from an entity wholly owned by Harold Hamm. Rents paid under these leases totaled approximately $143,000 for the year ended
December 31, 2007. These rates are consistent with the rates charged to other non-affiliated tenants in the building which we office.

In
connection with the completion of our initial public offering, we adopted an ethics policy that requires related party transactions be reviewed to ensure that they are fair and
reasonable to us. This requirement is also contained in our partnership agreement.

While
we do not have formal, specified policies or procedures for the review, approval or ratification of transactions required to be reported under paragraph (a) of
Regulation S-K Item 404, as related person transactions may result in potential conflicts of interest among management and board-level decision makers, our partnership
agreement does set forth procedures that our board of directors may utilize in connection with resolutions of potential conflicts of interest, including referral of such matters to an independent
conflicts committee for its review and approval or disapproval of such matters. For a discussion of our conflicts committee, see Item 10. ""Directors and Executive Officers of the Registrant."

Item 14.    Principal Accountant Fees and Services

Our audit committee has adopted an audit committee charter, which is available on our Web site at www.hilandpartners.com. The charter
requires our audit committee to approve in advance all audit and non-audit services to be provided by
our independent registered public accounting firm. Our audit committee ratified Grant Thornton LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of
Hiland Partners, LP for the year ended December 31, 2007. Audit fees paid to Grant Thornton LLP in 2007 include payments for our annual integrated audit, review of documents filed
with the Securities and Exchange Commission, Sarbanes Oxley Section 404 attest services and review of our quarterly reports on Form 10-Q. Fees for audit related services
relate to consultation regarding various business transactions. Tax fees include tax compliance, tax planning and acquisition matters. Fees paid in 2006 to Grant Thornton LLP for audit services
included fees associated with the annual audit, regulatory filings required in our initial and secondary public offerings, preparation for Sarbanes-Oxley Section 404 attest services and reviews
of our quarterly reports on Form 10-Q. Additional fees paid to Grant Thornton LLP for audit-related services consisted of consultation regarding an acquisition and for tax,
which consisted of compliance and advisory services. Fees paid to Grant Thornton LLP for the periods indicated are as follows:

2007

2006Audit Fees

$
338,000

$
372,000Audit Related Fees


11,000


8,000Tax Fees


121,000


165,000All Other Fees





Total

$
470,000

$
545,000


97

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PART IV

Item 15.    Exhibits and Financial Statement Schedules



The
financial statements listed in the accompanying Index to Consolidated Financial Statements are filed as part of this Annual Report on Form 10-K.



None.

EXHIBITS

|Exhibit
Number |  |   |  | Description                                                                                                                                                                                                                                      
|-------------- |  | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1            |  |  |  | Acquisition Agreement by and among Hiland Operating, LLC and Hiland Partners, LLC dated as of September 1, 2005 (incorporated by referenced to Exhibit 2.1 of Registrant's Form 8-K filed
September 29, 2005)                                    
|3.1            |  |  |  | Certificate of Limited Partnership of Hiland Partners, LP. (incorporated by reference to Exhibit 3.1 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                                                   
|3.2            |  |  |  | First Amended and Restated Limited Partnership Agreement of Hiland Partners, LP (incorporated by reference to exhibit 3.2 of Registrant's annual report on Form 10-K filed on March 30, 2005)                                                    
|3.3            |  |  |  | Certificate of Formation of Hiland Partners GP, LLC (incorporated by reference to Exhibit 3.3 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                                                          
|3.4            |  |  |  | Second Amended and Restated Limited Liability Company Agreement of Hiland Partners GP, LLC (incorporated by reference to exhibit 10.2 of Registrant's Form 8-K filed on September 29, 2006)                                                      
|10.1           |  |  |  | Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and MidFirst Bank (incorporated by reference to exhibit 10.1 of Registrant's annual report on Form 10-K filed on March 30, 2005)                                      
|10.2*          |  |  |  | Hiland Partners, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                                                                
|10.3           |  |  |  | Compression Services Agreement, effective as of January 28, 2005, by and among Hiland Partners, LP and Continental Resources, Inc. (incorporated by reference to exhibit 10.3 of Registrant's annual report on Form 10-K filed on
March 30, 2005)
|10.4          |  |  |  | Gas Purchase Contract between Continental Resources, Inc. and Continental Gas, Inc. (incorporated by reference to Exhibit 10.4 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                         
|10.5          |  |  |  | Gas Purchase Contract Chesapeake Energy Marketing, Inc. and Continental Gas, Inc. (incorporated by reference to Exhibit 10.5 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                           
|10.6          |  |  |  | Gas Purchase Contract between Magic Circle Energy Corporation and Magic Circle Gas (incorporated by reference to Exhibit 10.6 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                          

98

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|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 (incorporated
by reference to exhibit 10.8 of Registrant's annual report on Form 10-K filed on March 30, 2005)
|10.9*  |  |  |  | Form of Unit Option Grant (incorporated by reference to Exhibit 10.9 of Registrant's Registration Statement on Form S-1 (File No. 333-119908))                                                                                                                                                                                                                                                                                                                                                                                                  
|10.10  |  |  |  | Omnibus Agreement among Continental Resources, Inc., Hiland Partners, LLC, Harold Hamm, Hiland Partners GP, LLC, Continental Gas Holdings, Inc., and Hiland Partners, LP effective as of February 15, 2005
(incorporated by reference to exhibit 10.11 of Registrant's annual report on Form 10-K filed on March 30, 2005)                                                                                                                                                                                                                      
|10.11* |  |  |  | Director's Compensation Summary (incorporated by reference to exhibit 10.11 of Registrant's annual report on Form 10-K filed on March 30, 2005)                                                                                                                                                                                                                                                                                                                                                                                                 
|10.12* |  |  |  | Form of Restricted Unit Grant Agreement (incorporated by reference to exhibit 10.1 of Registrant's Form 8-K filed on November 14, 2005)                                                                                                                                                                                                                                                                                                                                                                                                         
|10.13  |  |  |  | First Amendment, dated as of September 26, 2005 to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to exhibit 10.1 of Registrant's Form 8-K filed
on September 29, 2005)                                                                                                                                                                                                                                                                                          
|10.14  |  |  |  | Gas Purchase Agreement among Hiland Partners, LP and Continental Resources, Inc. dated November 8, 2005 (incorporated by reference to exhibit 10.1 of Registrants form 8-K filed on November 10, 2005)                                                                                                                                                                                                                                                                                                                                          
|10.15  |  |  |  | Unit Purchase Agreement dated May 1, 2006 by and between Hiland Partners, LP and Hiland Partners GP, LLC (incorporated by reference to exhibit 10.1 of Registrants form 8-K filed on May 3, 2006)                                                                                                                                                                                                                                                                                                                                               
|10.16  |  |  |  | Asset Purchase Agreement dated March 30, 2006 by and between Hiland Operating, LLC and Enogex Gas Gathering, L.L.C. (incorporated by reference to exhibit 10.2 of Registrants form 8-K filed on May 3, 2006)                                                                                                                                                                                                                                                                                                                                    
|10.17  |  |  |  | Second Amendment, dated as of June 8, 2006, to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to exhibit 10.1 of Registrants form 8-K filed on
June 13, 2006)                                                                                                                                                                                                                                                                                                    
|10.18  |  |  |  | Non-Competition Agreement dated September 25, 2006 (2006 by and among Hiland Partners, LP, Hiland Holdings GP, LP and Hiland Partners GP Holdings, LLC (incorporated by reference to exhibit 10.1 of Registrants
form 8-K filed on September 29, 2006)                                                                                                                                                                                                                                                                                          
|10.19  |  |  |  | Retention Agreement, dated as of March 14, 2007, by and among Randy Moeder, Hiland Partners GP, LLC, Hiland Partners GP Holdings, LLC and the other parties listed on the signature page thereto. (incorporated by reference to
exhibit 10.1 of Registrant's Form 8-K filed on March 15, 2007)                                                                                                                                                                                                                                                  

99

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|10.20 |  |  |  | Third Amendment, dated as of July 13, 2007, to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to exhibit 10.1 of Registrant's Form 8-K filed on
July 18, 2007)        
|----- |  | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.21 |  |  |  | Form of Phantom Unit Grant Agreement (incorporated by reference to exhibit 10.1 of Registrant's Form 8-K filed on November 13, 2007)                                                                                                                 
|10.22 |  |  |  | Fourth Amendment, dated as of February 6, 2008, to Credit Agreement dated as of February 15, 2005 among Hiland Operating, LLC and the lenders thereto (incorporated by reference to exhibit 10.1 of Registrant's Form 8-K filed
on February 12, 2008)
|19.1  |  |  |  | Code of Ethics for Chief Executive Officer and Senior Finance Officers (incorporated by reference to exhibit 19.1 of Registrant's annual report on Form 10-K filed on March 30, 2005)                                                                
|21.1  |  |  |  | List of Subsidiaries of Hiland Partners, LP (incorporated by reference to exhibit 21.1 of Registrant's annual report on Form 10-K filed on March 30, 2005)                                                                                           
|23.1  |  |  |  | Consent of Grant Thornton LLP                                                                                                                                                                                                                        
|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                                                                                                                                                         

---

100

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized in the city of Enid, Oklahoma, on the 14th day of March, 2008.

| |  | HILAND PARTNERS,                                
| |  | ------------------------------------------------
| |  | By: Hiland Partners GP, LLC, its general
partner
| |  | By:                                             

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on
the 14th day of March, 2008.

|Signature                                   |  | Title                                                                   |  | 
|------------------------------------------- |  | ----------------------------------------------------------------------- |  | 
|                                            |  |                                                                         |  | 
|/s/HAROLD HAMMHarold Hamm                   |  | Chairman of the Board                                                   |  | 
|/s/JOSEPH L. GRIFFINJoseph L. Griffin       |  | Chief Executive Officer, President and Director                         |  | 
|/s/KEN MAPLESKen Maples                     |  | Chief Financial Officer, Vice PresidentFinance, Secretary and Director |  | 
|/s/MICHAEL L. GREENWOODMichael L. Greenwood |  | Director                                                                |  | 
|/s/EDWARD D. DOHERTYEdward D. Doherty       |  | Director                                                                |  | 
|/s/RAYFORD T. REIDRayford T. Reid           |  | Director                                                                |  | 
|/s/SHELBY E. ODELLShelby E. Odell           |  | Director                                                                |  | 
|/s/JOHN T. MCNABB, IIJohn T. McNabb, II     |  | Director                                                                |  | 
|/s/DR. DAVID L. BORENDr. David L. Boren     |  | Director                                                                |  | 

101

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                                                  |  |     
|--------------------------------------------------------------------------------------------------------------------------------- |  | ----
|Hiland Partners, LP Consolidated Financial Statements:                                                                            |  |     
|Management's Report on Internal Control Over Financial Reporting                                                                  |  | F-2 
|Reports of Independent Registered Public Accounting Firm                                                                          |  | F-3 
|Consolidated Balance Sheets as of December 31, 2007 and 2006                                                                      |  | F-5 
|Consolidated Statements of Operations for the years ended December 31, 2007, 2006
and 2005                                        |  | F-6 
|Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2006
and 2005                                        |  | F-7 
|Consolidated Statement of Changes in Owner's Equity and Comprehensive Income for the years ended December 31, 2007, 2006 and 2005 |  | F-9 
|Notes to Consolidated Financial Statements                                                                                        |  | F-10

F-1

---





Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d
-15(f) under the Securities and Exchange Act of 1934). Our internal control over financial reporting is a process designed by management, under the supervision of the Chief Executive Officer and Chief
Financial Officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America, and includes those policies and procedures that:



Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate. Accordingly,
even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.

Our
management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Company's internal control
over financial
reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal ControlIntegrated
Framework.

Based
on our evaluation under the framework in Internal Control-Integrated Framework, our management concluded that, as of December 31, 2007, our internal control over financial
reporting was effective.

Grant
Thornton LLP, the independent registered accounting firm who audited the consolidated financial statements included in this Annual Report, has issued a report on our
internal control over financial reporting. This report, dated March 13, 2008, appears on page F-3.

| | /S/  JOSEPH L. GRIFFINJoseph L. Griffin Chief Executive OfficerMarch 13, 2008
| | -----------------------------------------------------------------------------
| | /S/  KEN MAPLESKen Maples Chief Financial OfficerMarch 13, 2008              

F-2

---





Report of Independent Registered Public Accounting Firm

Board
of Directors
Hiland Partners GP, LLC

We
have audited internal control over financial reporting of Hiland Partners, LP and subsidiaries (the Partnership) as of December 31, 2007, based on criteria established
inInternal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The
Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting,
included in the accompanying "Management's Report on Internal Control Over Financial Reporting". Our responsibility is to express an opinion on the Partnership's internal control over financial
reporting based on our audit.

We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only
in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In
our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on Internal ControlIntegrated Frameworkissued by COSO.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Partnership as of
December 31, 2007 and 2006, and the related consolidated statements of operations, cash flows, and changes in partners' equity and comprehensive income for each of the three years in the period
ended December 31, 2007 and our report dated March 13, 2008 expressed an unqualified opinion.

/s/
GRANT THORNTON LLP

Oklahoma
City, Oklahoma
March 13, 2008

F-3

---



Report of Independent Registered Public Accounting Firm

Board
of Directors
Hiland Partners GP, LLC

We
have audited the accompanying consolidated balance sheets of Hiland Partners, LP and subsidiaries (the Partnership) as of December 31, 2007 and 2006, and the related
consolidated statements of operations, cash flows, and changes in partners' equity and comprehensive income for each of the three years in the period ended December 31, 2007. These financial
statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.

In
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Hiland Partners, LP and subsidiaries as
of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting
principles generally accepted in the United States of America.

As
discussed in Note 1 to the consolidated financial statements, the Partnership adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based
Payment, on a modified prospective basis as of January 1, 2006.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of
December 31, 2007, based on criteria established inInternal ControlIntegrated Frameworkissued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 13, 2008 expressed an unqualified opinion.

/s/
GRANT THORNTON LLP

Oklahoma
City, Oklahoma
March 13, 2008

F-4

---





HILAND PARTNERS, LP        Consolidated Balance Sheets        (in thousands, except unit amounts)

|                                              |                                                                                                                                    | December 31,
2007 |         | December 31,
2006
|--------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------------- | ----------------- | ------- | -----------------
|ASSETS                                        |                                                                                                                                    |                   |         |                  
|Current assets:                               |                                                                                                                                    |                   |         |                  
|Cash and cash equivalents                     |                                                                                                                                    | $                 | 10,497  |                  
|Accounts receivable:                          |                                                                                                                                    |                   |         |                  
|Trade                                         |                                                                                                                                    |                   | 31,841  |                  
|Affiliates                                    |                                                                                                                                    |                   | 1,479   |                  
|                                              |                                                                                                                                    |                   |         |                  
|                                              |                                                                                                                                    |                   | 33,320  |                  
|Fair value of derivative assets               |                                                                                                                                    |                   | 2,718   |                  
|Other current assets                          |                                                                                                                                    |                   | 1,155   |                  
|                                              |                                                                                                                                    |                   |         |                  
|Total current assets                          |                                                                                                                                    |                   | 47,690  |                  
|Property and equipment, net                   |                                                                                                                                    |                   | 319,320 |                  
|Intangibles, net                              |                                                                                                                                    |                   | 41,102  |                  
|Fair value of derivative assets               |                                                                                                                                    |                   | 418     |                  
|Other assets, net                             |                                                                                                                                    |                   | 1,943   |                  
|                                              |                                                                                                                                    |                   |         |                  
|Total assets                                  |                                                                                                                                    | $                 | 410,473 |                  
|                                              |                                                                                                                                    |                   |         |                  
|LIABILITIES AND PARTNERS' EQUITY              |                                                                                                                                    |                   |         |                  
|Current liabilities:                          |                                                                                                                                    |                   |         |                  
|Accounts payable                              |                                                                                                                                    | $                 | 24,709  |                  
|Accounts payableaffiliates                   |                                                                                                                                    |                   | 7,880   |                  
|Fair value of derivative liabilities          |                                                                                                                                    |                   | 8,238   |                  
|Accrued liabilities and other                 |                                                                                                                                    |                   | 2,075   |                  
|                                              |                                                                                                                                    |                   |         |                  
|Total current liabilities                     |                                                                                                                                    |                   | 42,902  |                  
|Commitments and contingencies (Note 7)        |                                                                                                                                    |                   |         |                  
|Long-term debt                                |                                                                                                                                    |                   | 226,104 |                  
|Fair value of derivative liabilities          |                                                                                                                                    |                   | 141     |                  
|Asset retirement obligation                   |                                                                                                                                    |                   | 2,159   |                  
|Partners' equity                              |                                                                                                                                    |                   |         |                  
|Limited partners' interest:                   |                                                                                                                                    |                   |         |                  
|                                              | Common unitholders (5,214,323 and 5,166,413 units issued and outstanding at December 31, 2007 and December 31, 2006, respectively) |                   |         | 130,066          
|                                              | Subordinated unitholders (4,080,000 units issued and outstanding)                                                                  |                   |         | 10,774           
|General partner interest                      |                                                                                                                                    |                   | 4,056   |                  
|Accumulated other comprehensive income (loss) |                                                                                                                                    |                   | (5,729  | )                
|                                              |                                                                                                                                    |                   |         |                  
|Total partners' equity                        |                                                                                                                                    |                   | 139,167 |                  
|                                              |                                                                                                                                    |                   |         |                  
|Total liabilities and partners' equity        |                                                                                                                                    | $                 | 410,473 |                  
|                                              |                                                                                                                                    |                   |         |                  

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

F-5

---





HILAND PARTNERS, LP        Consolidated Statements of Operations        (in thousands, except per unit amounts)

|                                                                          |  | Year Ended December 31, |        
|------------------------------------------------------------------------- |  | ----------------------- | -------
|
|Revenues:                                                                 |  |                         |        
|Midstream operations                                                      |  |                         |        
|Third parties                                                             |  | $                       | 269,769
|Affiliates                                                                |  |                         | 3,455  
|Compression services, affiliate                                           |  |                         | 4,819  
|                                                                          |  |                         |        
|Total revenues                                                            |  |                         | 278,043
|                                                                          |  |                         |        
|Operating costs and expenses:                                             |  |                         |        
|Midstream purchases (exclusive of items shown separately below)           |  |                         | 135,134
|Midstream purchasesaffiliate (exclusive of items shown separately below) |  |                         | 60,078 
|Operations and maintenance                                                |  |                         | 23,279 
|Depreciation, amortization and accretion                                  |  |                         | 29,855 
|General and administrative expenses                                       |  |                         | 7,587  
|                                                                          |  |                         |        
|Total operating costs and expenses                                        |  |                         | 255,933
|                                                                          |  |                         |        
|Operating income                                                          |  |                         | 22,110 
|                                                                          |  |                         |        
|Other income (expense):                                                   |  |                         |        
|Interest and other income                                                 |  |                         | 430    
|Amortization of deferred loan costs                                       |  |                         | (410   
|Interest expense                                                          |  |                         | (11,346
|                                                                          |  |                         |        
|Other income (expense), net                                               |  |                         | (11,326
|                                                                          |  |                         |        
|Net income                                                                |  |                         | 10,784 
|Less income attributable to predecessor                                   |  |                         |       
|Less general partner interest in net income                               |  |                         | 4,526  
|                                                                          |  |                         |        
|Limited partners' interest in net income                                  |  | $                       | 6,258  
|                                                                          |  |                         |        
|Net income per limited partners' unitbasic                               |  | $                       | 0.67   
|                                                                          |  |                         |        
|Net income per limited partners' unitdiluted                             |  | $                       | 0.67   
|                                                                          |  |                         |        
|Weighted average limited partners' units outstandingbasic                |  |                         | 9,284  
|                                                                          |  |                         |        
|Weighted average limited partners' units outstandingdiluted              |  |                         | 9,334  
|                                                                          |  |                         |        

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

F-6

---





HILAND PARTNERS, LP        Consolidated Statements of Cash Flows        (in thousands)

|                                                                                  |  | Year Ended December 31, |        
|--------------------------------------------------------------------------------- |  | ----------------------- | -------
|
|Cash flows from operating activities:                                             |  |                         |        
|Net income                                                                        |  | $                       | 10,784 
|Adjustments to reconcile net income to net cash provided by operating activities: |  |                         |        
|Depreciation and amortization                                                     |  |                         | 29,739 
|Accretion of asset retirement obligation                                          |  |                         | 116    
|Amortization of deferred loan cost                                                |  |                         | 410    
|Gain on derivative transactions                                                   |  |                         | (373   
|Unit based compensation                                                           |  |                         | 951    
|Increase in other assets                                                          |  |                         |       
|(Increase) decrease in current assets:                                            |  |                         |        
|Accounts receivabletrade                                                         |  |                         | (8,139 
|Accounts receivableaffiliates                                                    |  |                         | (195   
|Inventories                                                                       |  |                         |       
|Other current assets                                                              |  |                         | (430   
|Increase (decrease) in current liabilities:                                       |  |                         |        
|Accounts payable                                                                  |  |                         | 4,013  
|Accounts payableaffiliates                                                       |  |                         | 3,468  
|Accrued liabilities                                                               |  |                         | 358    
|                                                                                  |  |                         |        
|Net cash provided by operating activities                                         |  |                         | 40,702 
|                                                                                  |  |                         |        
|Cash flows from investing activities:                                             |  |                         |        
|Additions to property and equipment                                               |  |                         | (83,408
|Payments for Kinta Area assets acquired                                           |  |                         |       
|Acquisition of net assets of Hiland Partners, LLC, less cash received             |  |                         |       
|Proceeds from disposals of property and equipment                                 |  |                         |       
|                                                                                  |  |                         |        
|Net cash used in investing activities                                             |  |                         | (83,408
|                                                                                  |  |                         |        
|Cash flows from financing activities:                                             |  |                         |        
|Proceeds from initial public offeringnet                                         |  |                         |       
|Redemption of common units from organizers                                        |  |                         |       
|Distributions to organizers                                                       |  |                         |       
|Cash not contributed by organizers                                                |  |                         |       
|Payment of initial public offering costs                                          |  |                         |       
|Proceeds from long-term borrowings                                                |  |                         | 74,000 
|Payments on long-term borrowings                                                  |  |                         |       
|Payments on capital lease obligations                                             |  |                         | (296   
|Increase in deferred offering cost                                                |  |                         | (157   
|Debt issuance costs                                                               |  |                         | (501   
|Proceeds from secondary public offeringnet                                       |  |                         |       
|Payment of secondary public offering costs                                        |  |                         |       
|Cash distribution to controlling member for net assets of Hiland Partners, LLC    |  |                         |       
|General partner contribution for issuance of restricted common units              |  |                         | 6      
|Common units issued to our general partner                                        |  |                         |       
|Proceeds from unit options exercise                                               |  |                         | 1,055  
|Cash distributions to unitholders                                                 |  |                         | (31,290
|                                                                                  |  |                         |        
|Net cash provided by financing activities                                         |  |                         | 42,817 
|                                                                                  |  |                         |        
|Increase for the period                                                           |  |                         | 111    
|Beginning of period                                                               |  |                         | 10,386 
|                                                                                  |  |                         |        
|End of period                                                                     |  | $                       | 10,497 
|                                                                                  |  |                         |        
|Supplementary information                                                         |  |                         |        
|Cash paid for interest, net of amounts capitalized                                |  | $                       | 11,332 

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

F-7

---



HILAND PARTNERS, LP

Consolidated Statements of Cash Flows (Continued)

(in thousands)

|Non-cash investing and financing activities:                                                                      |  |   |         |  
|----------------------------------------------------------------------------------------------------------------- |  | - | ------- | -
|Property and equipment financed under capital lease obligations in the third quarter of 2007                      |  | $ | 5,881   |  
|                                                                                                                  |  |   |        
|Assumed asset retirement obligations on May 1, 2006 in connection with acquisition of Kinta Area gathering assets |  | $ | 1,106   |  
|                                                                                                                  |  |   |        
|Fair value of net assets acquired from Hiland Partners, LLC on February 15, 2005                                  |  |   |         |  
|Accounts receivable and other current assets                                                                      |  | $ | 162     |  
|Property and equipment                                                                                            |  |   | 31,600  |  
|Intangible assets                                                                                                 |  |   | 26,800  |  
|Other assets                                                                                                      |  |   | 105     |  
|                                                                                                                  |  |   |        
|Total assets acquired                                                                                             |  |   | 58,667  |  
|Less accounts payable and other current liabilities assumed                                                       |  |   | (741    | )
|Less current portion of long-term debt assumed                                                                    |  |   | (8,879  | )
|Less asset retirement obligation assumed                                                                          |  |   | (398    | )
|                                                                                                                  |  |   |        
|Fair value of net assets acquired                                                                                 |  |   | 48,649  |  
|Contributed for minority interest in subsidiary by affiliates                                                     |  |   | (47,282 | )
|                                                                                                                  |  |   |        
|Contributed for Hiland Partners GP, LLC                                                                           |  | $ | 1,367   |  
|                                                                                                                  |  |   |        

F-8

---





HILAND PARTNERS, LP        Consolidated Statement of Changes in Partners' Equity and Comprehensive Income        (in thousands, except unit amounts)

|                                                                                                                             |  | Predecessor
Equity |         | Common
Units |   | Subordinated
Units |   | General
Partner
Interest |         | Unearned
Compensation |   | Accumulated
Other
Comprehensive
Income (loss) |   | Total |      | Total
Comprehensive
Income |  
|---------------------------------------------------------------------------------------------------------------------------- |  | ------------------ | ------- | ------------ | - | ------------------ | - | ------------------------ | ------- | --------------------- | - | --------------------------------------------- | - | ----- | ---- | -------------------------- | -
|Balance, January 1, 2005                                                                                                     |  | $                  | 24,510  |              | $ |                   |   | $                        |        |                       | $ |                                              |   | $     |     |                            | $
|Assets not contributed to Hiland Partners, LP at initial public offering                                                     |  |                    | (9,972  | )            |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Net income from January 1, 2005 through February 14, 2005                                                                    |  |                    | 493     |              |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Allocation of net parent investment to affiliated unitholders (467,073 common units and 2,646,749 subordinated units)        |  |                    | (15,031 | )            |   | 2,191              |   |                          | 12,418  |                       |   | 422                                           |   |       |     |                            |  
|Contribution of certain net assets of Hiland Partners, LLC by owners (252,927 common units and 1,433,251 subordinated units) |  |                    |        |              |   | 7,092              |   |                          | 40,190  |                       |   | 1,367                                         |   |       |     |                            |  
|Proceeds from initial public offering, net of underwriter discount (2,300,000 common units)                                  |  |                    |        |              |   | 48,128             |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Offering costs of initial public offering                                                                                    |  |                    |        |              |   | (3,365             | ) |                          |        |                       |   |                                              |   |       |     |                            |  
|Redemption of Common Units from Organizers (300,000 common units)                                                            |  |                    |        |              |   | (6,278             | ) |                          |        |                       |   |                                              |   |       |     |                            |  
|Distributions to organizers                                                                                                  |  |                    |        |              |   | (362               | ) |                          | (3,489  | )                     |   |                                              |   |       |     |                            |  
|Cash distribution to controlling member for net assets of Hiland Partners, LLC                                               |  |                    |        |              |   | (2,507             | ) |                          | (24,473 | )                     |   | (788                                          | ) |       |     |                            |  
|Contribution by general partner                                                                                              |  |                    |        |              |   |                   |   |                          |        |                       |   | 7                                             |   |       |     |                            |  
|Proceeds from secondary public offering, net of underwriter discount (1,630,000 common units)                                |  |                    |        |              |   | 64,682             |   |                          |        |                       |   | 1,389                                         |   |       |     |                            |  
|Offering costs of secondary public offering                                                                                  |  |                    |        |              |   | (607               | ) |                          |        |                       |   |                                              |   |       |     |                            |  
|Periodic cash distributions to unitholders                                                                                   |  |                    |        |              |   | (3,268             | ) |                          | (4,896  | )                     |   | (185                                          | ) |       |     |                            |  
|Issuance of restricted units (8,000 common units)                                                                            |  |                    |        |              |   | 317                |   |                          |        |                       |   |                                              |   |       | (317 | )                          |  
|Unit based compensation                                                                                                      |  |                    |        |              |   |                   |   |                          |        |                       |   |                                              |   |       | 28   |                            |  
|Change in fair value of derivatives                                                                                          |  |                    |        |              |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Net income from February 15, 2005 through December 31, 2005                                                                  |  |                    |        |              |   | 4,004              |   |                          | 5,376   |                       |   | 464                                           |   |       |     |                            |  
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|Comprehensive Income                                                                                                         |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|Balance, January 1, 2006                                                                                                     |  |                    |        |              |   | 110,027            |   |                          | 25,126  |                       |   | 2,676                                         |   |       | (289 | )                          |  
|Elimination of unearned compensation upon                                                                                    |  |                    |        |              |   | (289               | ) |                          |        |                       |   |                                              |   |       | 289  |                            |  
|Issuance of 761,714 common units to our general partner                                                                      |  |                    |        |              |   | 34,300             |   |                          |        |                       |   | 700                                           |   |       |     |                            |  
|Proceeds from 52,699 unit options exercise                                                                                   |  |                    |        |              |   | 1,286              |   |                          |        |                       |   | 26                                            |   |       |     |                            |  
|Issuance of 13,000 restricted common units                                                                                   |  |                    |        |              |   |                   |   |                          |        |                       |   | 12                                            |   |       |     |                            |  
|Periodic cash distributions to unitholders                                                                                   |  |                    |        |              |   | (12,690            | ) |                          | (10,812 | )                     |   | (2,127                                        | ) |       |     |                            |  
|Unit based compensation                                                                                                      |  |                    |        |              |   | 473                |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Other comprehensive income reclassified to income on closed derivative transactions                                          |  |                    |        |              |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Change in fair value of derivatives                                                                                          |  |                    |        |              |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Net income                                                                                                                   |  |                    |        |              |   | 6,674              |   |                          | 5,599   |                       |   | 2,409                                         |   |       |     |                            |  
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|Comprehensive income                                                                                                         |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|Balance, December 31, 2006                                                                                                   |  |                    |        |              |   | 139,781            |   |                          | 19,913  |                       |   | 3,696                                         |   |       |     |                            |  
|Proceeds from 42,660 unit options exercise                                                                                   |  |                    |        |              |   | 1,034              |   |                          |        |                       |   | 21                                            |   |       |     |                            |  
|Issuance of 6,000 restricted common units                                                                                    |  |                    |        |              |   |                   |   |                          |        |                       |   | 6                                             |   |       |     |                            |  
|Periodic cash distributions to unitholders                                                                                   |  |                    |        |              |   | (15,214            | ) |                          | (11,883 | )                     |   | (4,193                                        | ) |       |     |                            |  
|Unit based compensation                                                                                                      |  |                    |        |              |   | 951                |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Other comprehensive income reclassified to income on closed derivative transactions                                          |  |                    |        |              |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Change in fair value of derivatives                                                                                          |  |                    |        |              |   |                   |   |                          |        |                       |   |                                              |   |       |     |                            |  
|Net income                                                                                                                   |  |                    |        |              |   | 3,514              |   |                          | 2,744   |                       |   | 4,526                                         |   |       |     |                            |  
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|Comprehensive income                                                                                                         |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  
|Balance, December 31, 2007                                                                                                   |  | $                  |        |              | $ | 130,066            |   | $                        | 10,774  |                       | $ | 4,056                                         |   | $     |     |                            | $
|                                                                                                                             |  |                    |         |              |   |                    |   |                          |         |                       |   |                                               |   |       |      |                            |  

The accompanying notes are an integral part of this consolidated financial statement.

F-9

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

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

Description of Business

Hiland Partners, LP, a Delaware limited partnership ("we," "us," "our," "HPLP" or "the Partnership"), was formed in October 2004 to acquire and operate
certain midstream natural gas plants, gathering systems and compression and water injection assets located in the states of Oklahoma, North Dakota, Wyoming, Texas and Mississippi that were previously
owned by Continental Gas, Inc. ("Predecessor" or "CGI") and Hiland Partners, LLC. We commenced operations on February 15, 2005, and concurrently with the completion of our initial
public offering, CGI contributed a substantial portion of its net assets to us. The transfer of ownership of net assets from CGI to us represented a reorganization of entities under common control and
was recorded at historical cost. CGI was formed in 1990 as a wholly owned subsidiary of Continental Resources, Inc. ("CLR").

CGI
operated in one segment, midstream, which involved the gathering, compressing, dehydrating, treating, and processing of natural gas and fractionating natural gas liquids, or NGLs.
CGI historically has owned all of our natural gas gathering, processing, treating and fractionation assets other than our Worland gathering system and our Bakken gathering system. Hiland
Partners, LLC historically owned our Worland gathering system and our compression services assets, which we acquired on February 15, 2005, and our Bakken gathering system. Since our
initial public offering, we have operated in midstream and compression services segments. On September 26, 2005, we acquired Hiland Partners, LLC, which at such time owned the Bakken
gathering system, for $92.7 million, $35.0 million of which was used to retire outstanding Hiland Partners, LLC indebtedness. On May 1, 2006, we acquired the Kinta Area
gathering assets from Enogex Gas Gathering, L.L.C., consisting of certain eastern Oklahoma gas gathering assets, for $96.4 million. We financed this acquisition with $61.2 million of
borrowings from our credit facility and $35.0 million of proceeds from the issuance to Hiland Partners GP, LLC, our general partner, of 761,714 common units and 15,545 general
partner equivalent units, both at $45.03 per unit.

Principles of Consolidation

The consolidated financial statements include our accounts and those of our subsidiaries. All significant intercompany transactions and balances have been
eliminated. The consolidated financial statements include the net assets and operations of assets owned by CGI and Hiland Partners, LLC that were contributed to us concurrently with the
completion of our initial public offering and also include the net assets and operations of Hiland Partners, LLC acquired effective September 1, 2005.

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.

F-10

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

For financial reporting, we consider all highly liquid investments with maturity of three months or less at date of purchase to be cash equivalents.

Accounts Receivable

The majority of our accounts receivable are due from companies in the oil and gas industry as well as the utility industry. Credit is extended based on evaluation
of the customer's financial condition. In certain circumstances, collateral, such as letters of credit or guarantees, is required. Accounts receivable are due within 30 days and are stated at
amounts due from customers. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and rights of offset. Credit losses are charged to
income when accounts are deemed uncollectible, determined on a case-by-case basis when we believe the required payment of specific
amounts owed is unlikely to occur. These losses historically have been minimal. Therefore, an allowance for uncollectible accounts is not required.

Concentration and Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and receivables. We place our
cash and cash equivalents with high-quality institutions and in money market funds. We derive our revenue from customers primarily in the natural gas and utility industries. These industry
concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or
other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable is
comprised primarily of mid-size to large domestic corporate entities.

Fair Value of Financial Instruments

Our financial instruments, which require fair value disclosure, consist primarily of cash and cash equivalents, accounts receivable, financial derivatives,
accounts payable and long-term debt. The carrying value of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair
values, due to the short maturity of these instruments. Derivative instruments are reported in the accompanying consolidated financial statements at fair value in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. Fair value of our derivative instruments is determined based on
management estimates through utilization of market data including forecasted forward natural gas and NGL prices as a function of forward NYMEX natural gas and light crude prices. The fair value of
long-term debt approximates its carrying value due to the variable interest rate feature of such debt.

F-11

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

Commodity Risk Management

We engage in price risk management activities in order to minimize the risk from market fluctuation in the prices of natural gas and NGLs. To qualify as a hedge,
the price movements in the commodity
derivatives must be highly correlated with the underlying hedged commodity. Gains and losses related to commodity derivatives which qualify as hedges are recognized in income when the underlying
hedged physical transaction closes and are included in the consolidated statements of operations as revenues from midstream operations. Gains and losses related to commodity derivatives that are not
designated as hedges or do not qualify as hedges are recognized in income immediately, and are included in midstream revenues in the consolidated statement of operations.

SFAS 133,
as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for
hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair
value. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through
earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. To qualify for cash flow hedge accounting, the cash flows from the hedging instrument
must be highly effective in offsetting changes in cash flows due to changes in the underlying item being hedged. In addition, all hedging relationships must be designated, documented, and reassessed
periodically. SFAS No. 133 also provides that normal purchases and normal sales contracts are not subject to the statement. Normal purchases and normal sales are contracts that provide for the
purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable
period in the normal course of business. Our forward natural gas purchase and sales contracts are designated as normal purchases and sales. Substantially all forward contracts fall within a
12 month term.

Currently,
our derivative financial instruments that qualify for hedge accounting are designated as cash flow hedges. The cash flow hedge instruments hedge the exposure of variability in
expected future cash flows that is attributable to a particular risk. The effective portion of the gain or loss on these derivative instruments is recorded in accumulated other comprehensive income in
partners' equity and reclassified into earnings in the same period in which the hedged transaction closes. The asset or liability related to the derivative instruments is recorded on the balance sheet
as fair value of derivative assets or liabilities. Any ineffective portion of the gain or loss is recognized in earnings immediately.

Property and Equipment

Our property and equipment are carried at cost. Depreciation and amortization of all equipment is determined under the straight-line method using
various rates based on useful lives, 10 to 22 years for pipeline and processing plants, and 3 to 10 years for corporate and other assets. The cost of assets and related accumulated
depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Maintenance, repairs and minor replacements are expensed
as incurred. Costs of replacements constituting improvement are capitalized.

F-12

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

Intangible Assets

Our intangible assets consist of the acquired value of existing contracts to sell natural gas and other NGLs and compression contracts, which do not have
significant residual value. The contracts are being amortized over their estimated lives of ten years. We review intangible assets for impairment whenever events or circumstances indicate that the
carrying amounts may not be recoverable. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value
based on the discounted probable cash flows of the intangible assets. No impairments of intangible assets were recorded during the years ended December 31, 2007, 2006 and 2005. On May 1,
2006 we acquired the Kinta Area gathering assets and recorded identifiable customer relationships of $10,492. Intangible assets consisted of the following for the periods indicated:

As of December 31,2007

2006Gas sales contracts

$
25,585

$
25,585Compression contracts


18,515


18,515Customer relationships


10,492


10,49254,592


54,592Less accumulated amortization


13,490


8,031Intangible assets, net

$
41,102

$
46,561


During
the years ended December 31, 2007 and 2006, we recorded amortization expense of $5,459 and $5,110, respectively. We had no intangible assets prior to February 15,
2005. Estimated aggregate amortization expense for each of the five succeeding fiscal years is $5,459 from 2008 through 2012 and a total of $13,807 for all years thereafter.

Long-Lived Assets

In accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets", we evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management's judgment, that the
carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on our management's estimate of undiscounted future cash flows attributable to the
assets as compared to the carrying value of the assets. If impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a
provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value
less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

F-13

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

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:



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.

No
impairment charges were recognized during each of the years ended December 31, 2007, 2006 and 2005.

Other Assets

Unamortized deferred loan costs related to the long-term debt on our bank credit facility totaling $1,641 and $1,550 as of December 31, 2007
and 2006, respectively, are included in other noncurrent assets. The deferred loan costs are amortized using the straight-line method over the term of the debt for the bank credit
facility.

Revenue Recognition

Revenues for sales and gathering of natural gas and NGLs are recognized at the time all gathering and processing activities are completed, the product is
delivered and title, if applicable, is transferred. Revenues related to our compression segment are recognized as monthly services are rendered under a four-year fixed-fee
contract that we entered into concurrently with our initial public offering.

Comprehensive Income

Comprehensive income includes net income and other comprehensive income, which includes, but is not limited to, changes in the fair value of derivative financial
instruments. Pursuant to SFAS No. 133, for derivatives qualifying as hedges, the effective portion of changes in fair value are

F-14

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

recognized
in owners' equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes. Comprehensive income consisted of the
following for the indicated periods:

Year Ended December 31,2007

2006

2005Net income

$
10,784

$
14,682

$
10,337Closed derivative transactions reclassified to income


(1,783
)

(3,582
)

Change in fair value of derivatives


(8,302
)

6,889


1,049Comprehensive income

$
699

$
17,989

$
11,386


Net Income per Limited Partners' Unit

Net income per limited partners' unit is computed based on the weighted-average number of common, subordinated and restricted units outstanding during the period.
The computation of diluted net income per limited partner unit further assumes the dilutive effect of unit options and restricted and phantom units. Net income per limited partners' unit is computed
by dividing net income applicable to limited partners, after deducting the general partner's 2% interest and incentive distributions, and, for 2005, after deducting net income attributable to the
Predecessor (before February 15, 2005), by both the basic and diluted weighted-average number of limited partnership units outstanding.

Environmental Costs

Environmental costs are expensed if they relate to an existing condition caused by past operations and do not contribute to current or future revenue generation.
Liabilities are recorded when site restoration and environmental remediation and cleanup obligations are either known or considered probable and can be reasonably estimated. Recoveries of
environmental costs through insurance, indemnification arrangements or other sources are included in other assets to the extent such recoveries are considered probable.

Income Taxes

As a partnership, we are not subject to income taxes. Therefore, there is no provision for income taxes included in our consolidated financial statements. Taxable
income, gain, loss and deductions are allocated to the unitholders who are responsible for payment of any income taxes thereon.

Net
income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial
reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders have different investment bases depending upon the
timing and price of acquisition of their partnership units. Furthermore, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting
followed in the consolidated

F-15

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

financial
statements. Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each
unitholder's tax attributes in our partnership is not available to us.

Transportation and Exchange Imbalances

In the course of transporting natural gas and NGLs for others, we may receive for redelivery different quantities of natural gas or NGLs than the quantities
actually redelivered. These transactions result in transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or NGLs in
future periods, if not subject to cashout provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the balance sheets and
marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. Changes in market value and the settlement of any such imbalance
at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold. As of December 31, 2007 and
2006, we had imbalance receivables of $454 and $1,028, respectively. We had no significant imbalance payables at either December 31, 2007 or December 31, 2006.

Share-Based Compensation

Our general partner, Hiland Partners GP, LLC adopted the Hiland Partners, LP Long-Term Incentive Plan for its employees and
directors of our general partner and employees of 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 is
administered by the compensation committee of our general partner's board of directors. The plan will continue in effect until the earliest of (i) the date determined by the board of directors
of our general partner; (ii) the date 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. Under the
unit option grant agreement, granted options of common units will vest and become exercisable in one-third increments on the anniversary of the grant date over three years. Vested options
are exercisable within the option's contractual life of ten years after the grant date.

F-16

---





HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

During the fourth quarter 2007, we granted 32,825 phantom units under our Long-Term Incentive Plan to our CFO, Vice President Operations and
Engineering and other key corporate and field employees. A phantom unit is a common unit that is subject to forfeiture and is not considered issued until it vests. Upon vesting, the phantom unit
holder will receive a common unit that is not subject to forfeiture, cash in lieu of the delivery of such unit equal to the fair market value of the unit on the vesting date, or a combination thereof,
at the discretion of our general partner's board of directors. Similar to restricted units, the phantom units granted to key corporate employees vest over a four-year period from the date
of issuance. The phantom units granted to key field employees vest one-third in year three and two-thirds in year four. The phantom units granted during the fourth quarter 2007
do not accumulate distributions.

On
June 19, 2007, we granted 10,000 phantom units under our Long-Term Incentive Plan to our new Chief Executive Officer, Joseph L. Griffin. Upon vesting,
Mr. Griffin will receive a common unit that is not subject to forfeiture, cash in lieu of the delivery of such unit equal to the fair market value of the unit on the vesting date, or a
combination thereof, at the discretion of our general partner's board of directors. Similar to restricted units, Mr. Griffin's phantom units vest over a four-year period from the
date of issuance and distributions on the phantom units will be held in trust by our general partner until the units vest.

The
weighted average fair value at grant date of the 42,825 phantom units granted during 2007 was $50.12. During the year ended December 31, 2007, we incurred compensation expense
of $249 related to the phantom units and will recognize additional expense of $1,721 over the next four years, and is to be recognized over a weighted average period of 2.5 years. We granted no
phantom units prior to June 19, 2007.

During
2007, we issued 1,000 restricted units each to six non-employee board members of our general partner on their one-year anniversary dates, and accordingly,
our general partner contributed $6 to us to maintain its 2% ownership interest. On the same anniversary dates of the six non-employee board members, 4,000 previously granted restricted
units vested and were converted to common units. Additionally, one fourth, or 1,250 restricted units granted to key employees in 2006 vested and were converted to common units. On November 15,
2007, 375 restricted units granted in November 2006 were forfeited and cancelled and the associated accumulated distributions held in trust by our general partner were returned to us.

Total
compensation expense related to restricted units was $537 and $119 for the years ended December 31, 2007 and 2006, respectively. As of December 31, 2007, there was
$533 of total unrecognized cost related to unvested restricted units, which is to be recognized over a weighted average period of 1.7 years.

A
restricted unit is a common unit that is subject to forfeiture. The restricted units vest over a four-year period from the date of issuance. Periodic distributions on the
restricted units are held in trust by our general partner until the units vest. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. Each non-employee board
member of our general partner is entitled to receive an additional 1,000 restricted common units on each anniversary date of the initial award.

F-17

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

The
following table summarizes information about restricted units for the year ended December 31, 2007.

Restricted Units

Units

Weighted Average Fair Value At Grant Date ($)Non-vested at January 1, 2007

19,000

$
44.12Granted

6,000

$
51.95Vested

(5,250
)
$
43.70Forfeited

(375
)
$
48.85Non-vested at December 31, 2007

19,375

$
46.57


In
October 1995 the FASB issued SFAS No. 123, "Share-Based Payment," which was revised in December 2004 ("SFAS 123R"). SFAS 123R requires that the compensation cost
relating to share-based payment transactions be recognized in the financial statements and that cost be measured based on the fair value of the equity or liability instruments issued. We adopted
SFAS 123R as of January 1, 2006 and applied SFAS 123R using the permitted modified prospective method beginning as of the same date and our unearned deferred compensation of $289
as of January 1, 2006 has been eliminated against common unit equity. Prior to January 1, 2006 we recorded any unamortized compensation related to restricted unit awards as unearned
compensation in equity. We expect no change to our cash flow presentation from the adoption of SFAS 123R since no tax benefits are recognized by us as a pass through entity. Our compensation
expense for these awards is recognized on the graded vesting attribution method. Units to be issued under our unit incentive plan may be from newly issued units. No compensation expense was recognized
in 2005 for our unit options granted during 2005. Prior to our adoption of SFAS 123R on January 1, 2006, we applied Accounting Principles Board Opinion No. 25 and related
interpretations in accounting for our unit-based compensation awards. The following pro forma data was calculated as if compensation cost for our unit-based compensation awards
during

F-18

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

the
year ended December 31, 2005 was determined based upon the fair value at the grant date consistent with the methodology prescribed under SFAS No. 123R.

Year Ended December 31, 2005Net income as reported

$
10,337Share based compensation adjustment


(419
)Pro forma net income


9,918Less income attributable to predecessor


(493
)Less general partner interest


(447
)Limited partner's interest in pro forma net income

$
8,978Net income per limited partner unit as reportedbasic

$
1.33Net income per limited partner unit as reporteddiluted

$
1.32Adjustmentbasic

$
(0.05
)Adjustmentdiluted

$
(0.05
)Pro forma net income per limited partner unitbasic

$
1.28Pro forma net income per limited partner unitdiluted

$
1.27Weighted average limited partner units outstandingbasic


7,034,000Weighted average limited partner units outstandingdiluted


7,086,000


The
fair value of each option granted was estimated on the date of grant using the American Binomial option-pricing model that used the assumptions noted below. Expected and
weighted-average volatility is based on our peer group volatility averages as determined on the option grant dates. Expected volatility of options granted ranged from 16% to 31% and weighted-average
volatility ranged from 18% to 30%. For options granted in 2006 and 2005, expected lives of 6.0 years are calculated by the simplified method as prescribed under SEC Staff Accounting Bulletin
107 and represent the period of time that unit options granted are expected to be outstanding. The risk-free interest rate for periods within the contractual life of the option is based on
the U.S. Treasury yield in effect at the time of grant. The exercise price of the options granted equaled the market price of the units on the grant date.

Year Ended December 31, 2006Expected volatility

16.1% - 20.2%Weighted-average volatility

18.0%Expected dividend yield

6.4%Risk-free interest rate

4.5%


F-19

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

The
following table summarizes information about outstanding options for the year ended December 31, 2007.

Options

Units

Weighted
Average Exercise Price ($)

Weighted-
Average Remaining Contractual Term (Years)

Aggregate Intrinsic Value ($)Outstanding at January 1, 2007

128,468

$
28.24Granted

Exercised

(42,660
)
$
24.15



$
1,315Forfeited or expired

(10,767
)
$
24.40Outstanding at December 31, 2007

75,041

$
31.11

7.6

$
1,459Exercisable at December 31, 2007

19,707

$
33.47

7.7

$
337


No
unit options were granted during 2007. The weighted average grant date fair value of the 28,000 unit options granted during the year ended December 31, 2006 was $4.33 per unit.
The weighted average grant date fair value of 167,500 unit options granted during the year ended December 31, 2005 was $5.30 per unit. The weighted average grant date fair value of 59,565 unit
options vested during the year ended December 31, 2007 was $9.84 per unit. As of December 31, 2007, there was $32 of total unrecognized compensation cost related to unvested unit based
option awards granted under our Plan. This cost is expected to be recognized over a weighted-average period of 0.4 years.

The
aggregate intrinsic value of options exercised were $1,315 and $876 for the years ended December 31, 2007 and 2006, respectively.

On
March 14, 2007, Randy Moeder, our past President, Chief Executive Officer and a director of our general partner announced his intention to resign. In connection with
Mr. Moeder's resignation, we and our general partner entered into a retention agreement with Mr. Moeder that allowed Mr. Moeder to continue his employment for a mutually agreeable
period of time, but no longer than six months. Under the agreement, as long as Mr. Moeder continued his employment, a pro rata portion of his 10,666 unvested options to purchase our common
units, issued to him on February 10, 2005, would vest. Accordingly, as required by SFAS 123R "Share-Based Payment," as amended, on March 14, 2007 we recalculated the fair value of
the remaining unvested options to purchase our common units as a modification of the options awarded to Mr. Moeder on February 10, 2005. The recalculated fair value of the options of
$33.65 per unit was determined by using the American Binomial option pricing model.

On
April 16, 2007, Mr. Moeder resigned and 1,899 of his 10,666 unvested options to purchase our common units vested. As a result of the recalculated fair value of $33.65
per unit, we recorded an additional $24 of expense for the period from March 15, 2007 through April 16, 2007. On the same day, Mr. Moeder forfeited his remaining 8,767 unvested
unit options. The forfeiture of Mr. Moeder's 8,767 unvested unit options reduced compensation expense for the period from April 1, 2007 through

F-20

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

April 16,
2007 by $16. On April 19, 2007, Mr. Moeder exercised his 1,899 vested options to purchase our common units.

On
April 14, 2006, 13,333 of the unit options issued on February 10, 2005, were forfeited. Compensation expense for the year ended December 31, 2006 has been reduced
by $21 as a result of the forfeiture.

As
a result of adopting SFAS 123R on the modified prospective basis beginning on January 1, 2006, we expensed $165 and $354 in 2007 and 2006, respectively, related to unit
options awarded in 2006 and 2005. We recognized no unit option compensation expense in 2005. Basic and diluted earnings per unit were each reduced by $0.04 for the year ended December 31, 2006
as a result of the additional compensation recognized under SFAS 123R.

Accounting for Asset Retirement Obligations

In accordance with SFAS No. 143, "Accounting for Asset Retirement Obligations," we have recorded the fair value of liabilities for asset retirement
obligations in the periods in which they are incurred and corresponding increases in the carrying amounts of the related long-lived assets. The asset retirement costs are subsequently
allocated to expense using a systematic and rational method and the liabilities are accreted to measure the change in liability due to the passage of time. The provisions of this standard primarily
apply to dismantlement and site restoration of certain of our plants and pipelines.

The
following table summarizes our activity related to asset retirement obligations:

Asset retirement obligation, January 1, 2006

$
1,024Acquired in Kinta Area acquisition on May 1, 2006


1,106Add: accretion expense


66Asset retirement obligation, December 31, 2006


2,196Add: additions on various leased locations


505Revisions of prior estimates


(658
)Add: accretion expense


116Asset retirement obligation, December 31, 2007

$
2,159


Recently Issued Accounting Pronouncements

In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations." This statement amends and replaces SFAS No. 141, but retains the
fundamental requirements in SFAS No. 141 that the purchase method of accounting be used for all business combinations and an acquirer be identified for each business combination. The statement
provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed and any non-controlling interest in the acquiree. SFAS 141(R) provides
for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. The statement also determines what information to disclose to enable
users to be able to evaluate the nature and financial effects of the

F-21

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

business
combination. The provisions of SFAS 141(R) apply prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period
beginning on or after December 15, 2008 and do not allow early adoption. We are evaluating the new requirements of Statement No. 141(R) and the impact it will have on business
combinations completed in 2009 or thereafter.

In
December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statementsan amendment of ARB No. 51." SFAS No. 160
establishes accounting and reporting standards that require the ownership interests in subsidiaries held by parties other than the parent (minority interest) be clearly identified, labeled, and
presented in the consolidated balance sheet within equity, but separate from the parent's equity. SFAS No. 160 requires the equity amount of consolidated net income attributable to the parent
and to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement and that changes in a parent's ownership interest while the parent retains its
controlling financial interest in its subsidiary be accounted for consistently and similarly as equity transactions. Consolidated net income and comprehensive income will be determined without
deducting minority interest; however, earnings-per-share information will continue to be calculated on the basis of the net income attributable to the parent's shareholders.
Additionally, SFAS No. 160 establishes a single method for accounting for changes in a parent's ownership interest in a subsidiary that does not result in deconsolidation and that the parent
recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. Early adoption is not
permitted. We do not expect this Statement will have a material impact on our financial position, results of operations or cash flows.

In
February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities". SFAS No. 159 expands opportunities to use fair value
measurement in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for fiscal years
beginning after November 15, 2007. This Statement was adopted by us effective January 1, 2008, at which time no financial assets or liabilities, not previously required to be recorded at
fair value by other authoritative literature, were designated to be recorded at fair value. As such, the adoption of this Statement did not have any impact on our financial position, results of
operations or cash flows.

In
September 2006, the FASB issued SFAS No. 157 "Fair Value Measurements." SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at the measurement date, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP)
such as fair value hierarchy used to classify the source of information used in fair value measurements (i.e., market based or non-market based) and expands disclosure about fair
value measurements based on their level in the hierarchy. This Statement applies to derivatives and other financial instruments, which Statement 133,Accounting for Derivative
Instruments and Hedging Activities, as amended, requires be measured at fair value at initial recognition and for all subsequent periods. This Statement is effective for
financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those

F-22

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 1: Description of Business and Summary of Significant Accounting Policies (Continued)

fiscal
years. We will apply the provisions of this Statement prospectively in the first quarter of 2008 and do not expect any significant impact on our financial position, results of operations or
cash flows.

Note 2: Initial Formation and Contribution of Assets

In connection with our formation and our initial public offering on February 15, 2005, the assets and liabilities of CGI excluding certain working capital
assets were contributed to us in exchange for 271,082 of our common units, after redemption of 195,991 common units, and 2,646,749 of our subordinated units. Existing bank debt of CGI was repaid from
the proceeds of our initial public offering.

All
of our initial assets were contributed by the former owners of CGI, Hiland Partners, LLC, and certain affiliates, including our general partner, in exchange for an aggregate
of 720,000 common units and 4,080,000 subordinated units, a 2% general partner interest in us and all of our incentive distribution rights, which entitle the general partner to increasing percentages
of the cash we distribute in excess of $0.495 per unit per quarter. The assets of CGI transferred to us are recorded at historical cost as it is considered to be a reorganization of entities under
common control and CGI is considered our accounting predecessor. The acquisition of the assets of Hiland Partners, LLC was accounted for as a purchase and, as a result, these assets were
recorded at their fair value at the time of purchase.

The
following table presents the assets and liabilities of our predecessor immediately prior to contributing assets to us, assets and liabilities contributed to us, and our predecessor's
assets and liabilities not contributed to us.

F-23

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 2: Initial Formation and Contribution of Assets (Continued)

Continental Gas, Inc. (Predecessor)  Assets Contributed to Hiland Partners, LP  As of February 15, 2005  (in thousands)

Continental Gas, Inc. (Predecessor) February 14, 2005

Net Assets Not Contributed

Contributed to Hiland Partners, LP February 15, 2005ASSETSCurrent assets:Cash and cash equivalents

$
869

$
869

$
Accounts Receivable


10,521


9,101


1,420Inventories


153





153Other current assets


291


2


289Total Current Assets


11,834


9,972


1,862Property and equipment, at cost, net


36,805





36,805Other assets, net


3,388





3,388Total assets


52,027


9,972


42,055LIABILITIESCurrent liabilities:Accounts payable


11,703





11,703Accrued liabilities


700





700Current maturities of long term debt


2,429





2,429Total current liabilities


14,832





14,832Long term debt, net of current maturities


11,570





11,570Asset retirement obligation


622





622Total liabilities


27,024





27,024NET ASSETS

$
25,003

$
9,972

$
15,031


In
consideration for the transfer, the owners of CGI received 467,073 of our common units and 2,646,749 of our subordinated units. Immediately following the closing of the offering,
195,991 of the common units were redeemed for approximately $4.1 million.

The
following table presents the assets and liabilities of Hiland Partners, LLC as of February 14, 2005, assets excluded from the acquisition, and the fair value of the
assets acquired.

F-24

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 2: Initial Formation and Contribution of Assets (Continued)

Hiland Partners, LLC  Assets Contributed to Hiland Partners, LP  As of February 15, 2005  (in thousands)

Hiland Partners, LLC February 14, 2005

Net Assets Not Contributed

Contributed to Hiland Partners, LP February 15, 2005

Fair ValueASSETSCurrent assets:Cash and cash equivalents

$
964

$
964

$


$
Accounts Receivable


2,619


2,503


116


116Other current assets


56


10


46


46Total Current Assets


3,639


3,477


162


162Property and equipment, at cost, net


50,063


29,858


20,205


31,600Intangible Assets











26,800Other assets, net


194


89


105


105Total assets


53,896


33,424


20,472


58,667LIABILITIESCurrent liabilities:Accounts payable


5,048


4,372


676


676Accrued liabilities


95


30


65


65Current maturities of long term debt


11,100


2,221


8,879


8,879Total current liabilities


16,243


6,623


9,620


9,620Long term debt, net of current maturities


24,253


24,253





Asset retirement obligation


398





398


398Total liabilities


40,894


30,876


10,018


10,018NET ASSETS

$
13,002

$
2,548

$
10,454

$
48,649


In
consideration for the transfer:



As
a part of the transactions, owners of CGI, Hiland Partners, LLC and certain members of our management received an aggregate of 138,776 equivalent units of our General Partner,
representing substantially all of the ownership of the general partner and a 2% equity ownership in us.

F-25

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 2: Initial Formation and Contribution of Assets (Continued)

The proceeds of the public offering were used to: redeem an aggregate of 300,000 common units from former owners for $6.3 million; repay
$14.0 million in debt owed by CGI and $8.9 million in debt contributed from Hiland Partners, LLC; pay the remaining $2.2 million of expenses associated with the offering
and formation transactions; pay $0.6 million of debt issuance costs related to the credit facility; distribute $3.9 million to the former owners of Hiland Partners, LLC in
reimbursement of certain capitalized expenditures related to the assets of Hiland Partners, LLC that were contributed to us; and replenish approximately $12.2 million of working capital.

Note 3: Acquisitions

Kinta Area Gathering System.On May 1, 2006, we acquired certain gas gathering assets from Enogex Gas Gathering,
L.L.C. for $96.4 million cash, including certain closing costs, financed with the issuance of 761,714 common units and 15,545 general partner equivalent units to our general partner for
proceeds of $35.0 million and borrowings of $61.2 million under our credit facility. We refer to these assets as the Kinta Area gathering assets. A determination was made by our
management of the fair value of these assets and liabilities as required by SFAS 141 "Business Combinations," primarily using current replacement cost for the acquired gas gathering assets and
related equipment less estimated accumulated depreciation on such replacement costs; and estimated discounted cash flows arising from future renegotiated customer contracts. The acquired assets at the
time of the acquisition, which are located in the eastern Oklahoma Arkoma Basin, had approximately 672 wellhead receipt points and included five separate low pressure natural gas gathering systems,
which consisted of over 569 miles of natural gas gathering pipelines and 23 compressors with an aggregate of approximately 40,000 horsepower. The natural gas gathering systems operate under contracts
with producers that provide for services under fixed-fee arrangements. We operate the Kinta Area gathering assets substantially differently than were operated by the previous owner. Since
there was no sufficient
continuity of the Kinta Area gathering assets' operations prior to and after our acquisition, disclosure of prior financial information would not be material to an understanding of future operations.
Therefore, the acquisition has been recorded as a purchase of assets and not of a business and no pro forma financial information is required to be presented.

The
following table presents the resulting allocation to the net assets acquired and liabilities assumed on May 1, 2006:

Pipelines, including right of ways

$
56,175Compressors


22,221Land, buildings and other equipment


8,618Customer relationships


10,49297,506Asset retirement obligation assumed


1,106Net assets acquired

$
96,400


The
Kinta Area gathering assets and operations are included in the consolidated financial statements from May 1, 2006 forward.

F-26

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 3: Acquisitions (Continued)

Hiland Partners, LLC, (Bakken).On September 26, 2005, we completed our acquisition of Hiland
Partners, LLC, an Oklahoma limited liability company, for approximately $92.7 million in cash, $35.0 million of which was used to retire outstanding Hiland Partners, LLC
indebtedness. The effective date of the acquisition was September 1, 2005. Hiland Partners, LLC's principal asset was the Bakken gathering system located in Richland County, Montana. At
the time of the acquisition, the Bakken gathering system consisted of approximately 256 miles of gas gathering pipeline, a natural gas processing plant, two compressor stations, which were comprised
of three compressors 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. To
facilitate the closing of the acquisition, we amended our senior secured revolving credit facility to increase our borrowing capacity under the facility from $55.0 million to
$125.0 million, consisting of a $117.5 million acquisition facility and a $7.5 million working capital facility. We used a portion of this increased capacity to fund the
acquisition.

To
the extent of our non-controlling ownership of Hiland Partners, LLC, the acquisition was accounted for using the purchase method of accounting under SFAS
No. 141, "Business Combinations". As of the date of our acquisition, Hiland Partners, LLC was an entity partially owned by an affiliate who, at the time, was a controlling member of our
general partner. Accordingly, 49% of the Bakken gathering system assets, for which estimated fair value was in excess of historical basis, have been recorded at historical cost and 51% of the Bakken
gathering system assets have been recorded at fair value. A cash distribution of $27.8 million made to this affiliate, as reported as a reduction of owners' equity, reflects the difference in
the purchase price paid to this affiliate and his cost basis in the net assets of Hiland Partners, LLC. The fair value of the assets acquired has also been reduced by imputed interest expense
from September 1, 2005, the effective date of the acquisition, through the closing date, September 26, 2005. The following table presents the resulting allocation to the net assets
acquired and liabilities assumed at the effective date of acquisition:

Cash and cash equivalents

$
300Accounts receivable


3,708Other current assets


20Property, plant and equipment


49,873Customer contracts


17,589Total assets acquired


71,490Accounts payable


(6,217
)Accrued liabilities


(125
)Total liabilities assumed


(6,342
)Net assets of Hiland Partners, LLC


65,148Imputed interest expense


(289
)Purchase price of net assets of Hiland Partners, LLC less distribution to the controlling member

$
64,859


F-27

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 3: Acquisitions (Continued)

The
operations of the Bakken gathering system are included in the statement of operations and statement of cash flows from September 1, 2005 forward. The operations of the assets
acquired from Hiland Partners, LLC in note 2 above are included in the statement of operations and statement of cash flows from February 15, 2005 forward. Had the acquisitions
been made effective January 1, 2005, the operations of the assets would have been included in our consolidated financial statements for the indicated periods with the following pro forma impact
on the consolidated combined statements of operations for 2005.

Revenues as reported

$
166,601Revenues from acquired interests


18,648Pro forma revenues

$
185,249Net income as reported

$
10,337Loss from acquired interests


(4,176
)Pro forma net income


6,161Less income attributable to predecessor


(493
)Less general partner interest in pro forma net income


(378
)Limited partners' interest in pro forma net income

$
5,290Pro forma net income per limited partner unitbasic

$
0.75Pro forma net income per limited partner unitdiluted

$
0.75Weighted average limited partner units outstandingbasic


7,034,000Weighted average limited partner units outstanding,diluted


7,086,000


Note 4: Property and Equipment

As of December 31,2007

2006Land

$
295

$
255Construction in progress


12,030


48,610Midstream pipeline, plants and compressors


352,003


226,157Compression and water injection equipment


19,258


19,270Other


3,958


2,471387,544


296,763Less: accumulated depreciation and amortization


68,224


43,962$
319,320

$
252,801


During
the third quarter 2007, we purchased two separate capital assets under capital lease obligations for a total cost of $5,881. Accumulated depreciation related to the assets
purchased under capital lease obligations was $175 as of December 31, 2007.

F-28

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 4: Property and Equipment (Continued)

We
capitalized interest of $2,580 and $1,467 during the year ended December 31, 2007 and 2006, respectively. Depreciation charged to expense totaled $24,280, $16,954, and $8,162
for the years ended December 31, 2007, 2006 and 2005, respectively.

Note 5: Derivatives

We have entered into certain financial swap instruments that are classified as cash flow hedges in accordance with SFAS No. 133, as amended, and relate to
forecasted sales in 2008 and 2009. We entered into these instruments to hedge forecasted natural gas and NGL sales or purchases against the variability in expected future cash flows attributable to
changes in commodity prices. Under all but one of these contractual swap agreements with our counterparties, we receive a fixed price and pay a floating price based on certain indices for the relevant
contract period as the underlying natural gas or NGL is sold. In one agreement, we pay a fixed price and receive a floating price based on certain indices for the relevant contract period as the
underlying natural gas is purchased.

We
formally document all relationships between hedging instruments and the items being hedged, including our risk management objective and strategy for undertaking the hedging
transactions. This
includes matching the natural gas and NGL futures, the "sold fixed for floating price" or "buy fixed for floating price" contracts, to the forecasted transactions. We assess, both at the inception of
the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Highly effective is deemed to be a correlation range from 80%
to 125% of the change in cash flows of the derivative in offsetting the cash flows of the hedged transaction. If it is determined that a derivative is not highly effective as a hedge or it has ceased
to be a highly effective hedge, due to the loss of correlation between changes in natural gas or NGL reference prices under a hedging instrument and actual natural gas or NGL prices, we will
discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. We assess effectiveness using regression analysis
and ineffectiveness using the dollar offset method.

Derivatives
are recorded on our consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value
are recognized in owners' equity as accumulated other comprehensive income and reclassified to earnings when the underlying hedged physical transaction closes. For non-qualifying
derivatives and for the ineffective portion of qualifying derivatives, changes in fair value are recognized in earnings as they occur. Actual amounts that will be reclassified will vary as a result of
future changes in prices. Hedge ineffectiveness is recognized as an adjustment to midstream revenue while the hedge contract is open and may increase or decrease until settlement of the contract.
Realized cash gains and losses on closed/settled instruments are reflected in the contract month being hedged as an adjustment to our midstream revenues.

During
the year ended December 31, 2007 we reclassified net losses of $1,783 on closed/settled hedge transactions to midstream revenues out of other comprehensive income and also
recorded ($8,302) to other comprehensive income for the unfavorable change in fair value of open derivatives. During the year ended December 31, 2007, we recorded losses of $45, on the
ineffective portions of

F-29

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 5: Derivatives (Continued)

our
qualifying open derivative transactions and a gain of $418 on the one derivative that did not qualify for hedge accounting. Subsequent to December 31, 2007, on January 8, 2008, we
contracted a fixed sales price of $7.535 per MMBtu on the derivative that did not qualify for hedge accounting, which, in our opinion, will now qualify for hedge accounting in 2008. At
December 31, 2007, our accumulated other comprehensive income (loss) related to derivatives was ($5,729). Of this amount, we anticipate ($5,588) will be reclassified to earnings during the next
twelve months and ($141) will be reclassified to earnings in subsequent periods. We first entered into derivative transactions in October 2005 and had no closed/settled hedge transactions or
ineffective portions of qualifying open derivative transactions during the year ended December 31, 2005.

The
fair value of derivative assets and liabilities are as follows for the indicated periods:

As of December 31,2007

2006Fair value of derivative assetscurrent

$
2,718

$
4,707Fair value of derivative assetslong term


418


1,955Fair value of derivative liabilitiescurrent


(8,238
)

(1,902
)Fair value of derivative liabilitieslong term


(141
)

(291
)Net fair value of derivatives

$
(5,243
)
$
4,469


The
following table summarizes our activity related to derivative transactions for the indicated periods:

For the Years Ended December 31,2007

2006

2005Net gains on closed/settled transactions

$
1,783

$
3,582

$
Changes in fair values of open derivatives

$
(8,302
)
$
6,889

$
1,049Unrealized gains on non-qualifying open derivatives

$
418

$


$
Unrealized gains (losses) on qualifying open derivatives

$
(45
)
$
113

$



F-30

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 5: Derivatives (Continued)

The
terms of our derivative contracts currently extend as far as December 2009. Our counterparty to all of our derivative contracts is BP Energy Company. Set forth below is the
summarized notional amount and terms of all instruments held for price risk management purposes at December 31, 2007.

|Description and Production Period                       |  | Volume    |   | Average
Fixed/Open
Price |             | Fair Value
Asset
(Liability) |  
|------------------------------------------------------- |  | --------- | - | ------------------------ | ----------- | ---------------------------- | -
|Natural GasSold Fixed for Floating Price Swaps         |  | (MMBtu    | ) |                          | (per MMBtu  | )                            |  
|                                                        |  |           |   |                          |             |                              |  
|January 2008 - December 2008                            |  | 1,980,000 |   | $                        | 7.84        |                              | $
|January 2009 - December 2009                            |  | 1,068,000 |   | $                        | 7.06        |                              |  
|                                                        |  |           |   |                          |             |                              |  
|                                                        |  |           |   |                          |             |                              | $
|                                                        |  |           |   |                          |             |                              |  
|Natural GasSold Open for Floating Price Swaps          |  | (MMBtu    | ) |                          | (per MMBtu  | )                            |  
|                                                        |  |           |   |                          |             |                              |  
|January 2009 - December 2009                            |  | 1,068,000 |   | $                        | 7.35        |                              | $
|                                                        |  |           |   |                          |             |                              |  
|Natural GasBuy Fixed for Floating Price Swaps          |  | (MMBtu    | ) |                          | (per MMBtu  | )                            |  
|                                                        |  |           |   |                          |             |                              |  
|January 2008 - December 2008                            |  | 790,569   |   | $                        | 7.33        |                              | $
|                                                        |  |           |   |                          |             |                              |  
|Natural Gas LiquidsSold Fixed for Floating Price Swaps |  | (Bbls     | ) |                          | (per Gallon | )                            |  
|                                                        |  |           |   |                          |             |                              |  
|January 2008 - December 2008                            |  | 441,768   |   | $                        | 1.30        |                              | $
|                                                        |  |           |   |                          |             |                              |  

Note 6: Long-Term Debt

As of December 31,2007

2006Note payablebank

$
221,064

$
147,064Capital lease obligations


5,585


226,649


147,064Less: current portion of capital lease obligations


545


Long-term debt

$
226,104

$
147,064


Credit Facility.On February 6, 2008, we entered into a fourth amendment to our credit facility dated as of
February 15, 2005. Pursuant to the fourth amendment, we have, among other things, increased our borrowing base from $250 million to $300 million and decreased the accordion
feature in the facility from $100 million to $50 million. Our original credit facility dated May 2005 was first amended in September 2005, amended a second time in June 2006 and amended
a third time in July 2007.

The
fourth amendment increases our borrowing capacity under our senior secured revolving credit facility to $300 million such that the facility now consists of a
$291 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
"Acquisition Facility") and a $9.0 million senior secured

F-31

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 6: Long-Term Debt (Continued)

revolving
credit facility to be used for working capital and to fund distribution (the "Working Capital Facility").

In
addition, the fourth amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to
$50 million and allows for the issuance of letters of credit of up to $15 million in the aggregate. The senior secured revolving credit facility also requires us to meet certain
financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain
permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and
a minimum interest coverage ratio of 3.0:1.0. The credit facility will mature in May 2011. 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.

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 125 basis points per
annum or (ii) LIBOR plus an applicable margin ranging from 150 to 225 basis points per annum based on our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rate per
annum equal to the greatest of (a) the Prime Rate in effect on such day, (b) the base CD rate in effect on such day plus 1.50% and (c) the Federal Funds effective rate in effect
on such day plus 1/2 of 1%. A letter of credit fee will be payable for the aggregate amount of letters of credit issued under the credit facility at a percentage per annum equal to
1.0%. An unused commitment fee ranging from 25 to 50 basis points per annum based on our ratio of consolidated funded debt to EBITDA will be payable on the unused portion of the credit facility.
During any step-up period, the applicable margin with respect to loans under the credit facility will be increased by 35 basis points per annum and the unused commitment fee will be
increased by 12.5 basis points per annum. At December 31, 2007, the interest rate on outstanding borrowings from our credit facility was 7.19%.

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 its business, amend its material agreements, including the Omnibus Agreement or
enter into a merger, consolidation or sale of assets.

The
credit facility defines EBITDA as our consolidated net income, plus income tax expense, interest expense, depreciation and amortization expense, amortization of intangibles and
organizational costs, non-cash unit based compensation expense, and adjustments for non-cash gains and losses on specified derivative transactions and for other extraordinary
items.

F-32

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 6: Long-Term Debt (Continued)

Upon
the occurrence of an event of default as defined in 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.

The
credit facility limits distributions to our unitholders to available cash, as defined by the agreement, and borrowings to fund such distributions are only permitted under the
revolving working capital facility. The revolving working capital facility is subject to an annual "clean-down" period of 15 consecutive days in which the amount outstanding under the
revolving working capital facility is reduced to zero.

As
of December 31, 2007, we had $221.1 million outstanding under the credit facility and were in compliance with its financial covenants.

Capital Lease Obligations.During the third quarter 2007, we incurred a $4,836 capital lease obligation at our Bakken
gathering system resulting from a NGL marketing agreement with a business partner whereby they have constructed a rail loading facility and a products pipeline, and we have agreed to repay the
business partner a predetermined amount over a period of eight years. As specified in the agreement, once fully paid, title to the rail loading facility and the products pipeline will transfer to us
no later than the end of the eight year period.

In
order to supply adequate electric power supply to our new nitrogen rejection plant at our Badlands gathering system, also during the third quarter 2007, we incurred a $1,045 capital
lease obligation for the aid to construction of several electric substations which, by agreement, will be repaid in equal monthly installments over a period of five years.

During
the year ended December 31, 2007, we made principal payments of $296 on the above described capital lease obligations. The current portion of the capital lease obligations
presented in the table above is included accrued liabilities and other in the balance sheet.

Note 7: Commitments and Contingencies

We have executed a natural gas fixed price physical forward sales contract on 100,000 MMBtu per month for 2008 with a fixed price of $8.43 per MMBtu. This
contract has been designated as a normal sale under SFAS No. 133 and is therefore not marked to market as a derivative.

We
maintain a defined contribution retirement plan for our employees under which we make discretionary contributions to the plan based on a percentage of eligible employees'
compensation. Contributions to the plan are 5.0% of eligible employees' compensation and resulted in expenses for the three years ended December 31, 2007, 2006 and 2005 of $262, $201 and $111,
respectively.

Prior
to January 1, 2007, we jointly participated with other affiliated companies in a self-insurance pool (the "Pool") covering health and workers' compensation
claims made by employees up to the first $150 and $500, respectively, per claim. Any amounts paid above these were reinsured through third party providers. Premiums charged to us were based on
estimated costs per employee of the Pool. Effective January 1, 2007, we obtained our own health and workers' compensation insurance through third-party providers. Property and general liability
insurance is also maintained through third-party providers with a $100 deductible on each policy.

F-33

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 7: Commitments and Contingencies (Continued)

The operation of pipelines, plants and other facilities for gathering, compressing, treating, or processing natural gas, NGLs and other products is subject to
stringent and complex laws and regulations pertaining to health, safety and the environment. Our management believes that compliance with federal, state or local environmental laws and regulations
will not have a material adverse effect on our business, financial position or results of operations.

Although
there are no regulatory proceedings in which we are currently involved, periodically we may be a party to regulatory proceedings. The results of regulatory proceedings cannot be
predicted with certainty; however, our management believes that we presently do not have material potential liability in connection with regulatory proceedings that would have a significant financial
impact on our consolidated financial condition, results of operations or cash flows.

We
lease office space from a related entity (Note 9). We also lease certain facilities, vehicles and equipment under operating leases, most of which contain annual renewal
options. For the years ended 2007, 2006 and 2005, rent expense was $2,285, $779 and $224, respectively, under these leases.

A
summary of our contractual cash obligations as of December 31, 2007, including minimum future rental commitments under operating leases having non-cancelable lease
terms in excess of one year, and leases renewed and entered into subsequent to year end but prior to financial statement issuance, is presented below:

|                                               |  |   |         | Payment Due by Period |   |      
|---------------------------------------------- |  | - | ------- | --------------------- | - | -----
|
|
|Senior secured revolving credit facility       |  | $ | 221,064 |                       | $ |     
|Capital lease obligations(1)                   |  |   | 8,634   |                       |   | 1,256
|Operating leases, service agreements and other |  |   | 3,720   |                       |   | 1,667
|                                               |  |   |         |                       |   |      
|Total contractual cash obligations             |  | $ | 233,418 |                       | $ | 2,923
|                                               |  |   |         |                       |   |      

---

F-34

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 8:  Significant Customers and Suppliers

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

For the Year ended December 31,2007

2006

2005Customer 1

19
%
20
%
16
%Customer 2

19
%
14
%
6
%Customer 3

12
%
2
%
Customer 4

11
%
15
%



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

For the Year ended December 31,2007

2006

2005Supplier 1 (affiliated company)

31
%
32
%
29
%Supplier 2

25
%
24
%
26
%Supplier 3

14
%
13
%
14
%


Note 9:  Related Party Transactions

We purchase natural gas and NGLs from affiliated companies. Purchases of product from affiliates totaled $60.1 million, $50.3 million, and
$45.8 million for the years ended December 31, 2007, 2006 and 2005, respectively. We sell natural gas and NGLs to affiliated companies. Sales of product to affiliates totaled
$3.5 million, $4.1 million, and $5.2 million for the years ended December 31, 2007, 2006 and 2005, respectively. Compression revenues from affiliates were
$4.8 million each for 2007 and 2006 and $4.2 million for the year ended December 31, 2005.

Accounts
receivable-affiliates of $1,479 and $1,284 at December 31, 2007 and 2006, respectively, includes $1,090 and $1,260 from one affiliate for midstream sales.

Accounts
payable-affiliates of $7,880 and $4,412 at December 31, 2007 and 2006, respectively, includes $7,094 and $3,819 due to one affiliate for midstream purchases.

We
utilize affiliated companies to provide services to our plants and pipelines and certain administrative costs. The total amount paid to these companies was $525, $353, and $336 during
the years ended December 31, 2007, 2006 and 2005, respectively.

We
lease office space under operating leases directly or indirectly from an affiliate. Rents paid associated with these leases totaled $143, $118, and $75 for the years ended
December 31, 2007, 2006 and 2005, respectively.

Note 10:  Reportable Segments

On February 15, 2005, certain assets and liabilities of Hiland Partners, LLC were contributed to us in conjunction with our initial public offering.
As a result of this transaction, we have distinct operating

F-35

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 10:  Reportable Segments (Continued)

segments
for which additional financial information must be reported. Prior to February 15, 2005, we did not have operating segments. Our operations are now classified into two reportable
segments:



These
segments reflect the way we manage our operations. Our operations are conducted in the United States. General and administrative costs, which consist of executive management,
accounting and finance, operations and engineering, marketing and business development, are allocated to the individual segments based on revenues.

Midstream
assets totaled $382,626 and $312,431 at December 31, 2007 and 2006, respectively. On the same dates, assets attributable to compression operations totaled $27,847 and
$31,385, respectively. All but $48 of the $90,953 total additions to property and equipment for the year ended December 31, 2007 was attributable to midstream operations. All but $72 of the
total additions to property and equipment of $62,137 and Kinta Area gathering assets acquired of $96,400 for the year ended December 31, 2006 was attributable to midstream operations. Capital
expenditures of $10,389 for the year ended December 31, 2005 were entirely related to the midstream segment.

The
table below presents information about operating income for the reportable segments for the years ended December 31, 2007, 2006 and 2005.

|                                                                |                                    | Midstream Segment |         | Compression Segment |   | Total |      
|--------------------------------------------------------------- | ---------------------------------- | ----------------- | ------- | ------------------- | - | ----- | -----
|For the Year Ended December 31, 2007                            |                                    |                   |         |                     |   |       |      
|Revenues                                                        |                                    | $                 | 273,224 |                     | $ | 4,819 |      
|Operating costs and expenses:                                   |                                    |                   |         |                     |   |       |      
|Midstream purchases (exclusive of items shown separately below) |                                    |                   | 195,212 |                     |   |      |      
|Operations and maintenance                                      |                                    |                   | 22,472  |                     |   | 807   |      
|Depreciation and amortization                                   |                                    |                   | 26,277  |                     |   | 3,578 |      
|General and administrative expenses                             |                                    |                   | 7,456   |                     |   | 131   |      
|                                                                |                                    |                   |         |                     |   |       |      
|                                                                | Total operating costs and expenses |                   |         | 251,417             |   |       | 4,516
|                                                                |                                    |                   |         |                     |   |       |      
|Operating income                                                |                                    |                   | 21,807  |                     |   | 303   |      
|                                                                |                                    |                   |         |                     |   |       |      
|Other income (expense):                                         |                                    |                   |         |                     |   |       |      
|Interest and other income                                       |                                    |                   |         |                     |   |       |      
|Amortization of deferred loan costs                             |                                    |                   |         |                     |   |       |      
|Interest expense                                                |                                    |                   |         |                     |   |       |      
|                                                                |                                    |                   |         |                     |   |       |      
|                                                                | Total other income (expense)       |                   |         |                     |   |       |      
|                                                                |                                    |                   |         |                     |   |       |      
|Net income                                                      |                                    |                   |         |                     |   |       |      
|                                                                |                                    |                   |         |                     |   |       |      

F-36

---



HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 10:  Reportable Segments (Continued)

|For the Year Ended December 31, 2006                            |                                    |   |         |         |   |       |       |   |         |        
|--------------------------------------------------------------- | ---------------------------------- | - | ------- | ------- | - | ----- | ----- | - | ------- | -------
|Revenues                                                        |                                    | $ | 214,867 |         | $ | 4,819 |       | $ | 219,686 |        
|Operating costs and expenses:                                   |                                    |   |         |         |   |       |       |   |         |        
|Midstream purchases (exclusive of items shown separately below) |                                    |   | 156,193 |         |   |      |       |   | 156,193 |        
|Operations and maintenance                                      |                                    |   | 15,228  |         |   | 843   |       |   | 16,071  |        
|Depreciation and amortization                                   |                                    |   | 18,559  |         |   | 3,571 |       |   | 22,130  |        
|General and administrative expenses                             |                                    |   | 4,884   |         |   | 110   |       |   | 4,994   |        
|                                                                |                                    |   |         |         |   |       |      
|                                                                | Total operating costs and expenses |   |         | 194,864 |   |       | 4,524 |   |         | 199,388
|                                                                |                                    |   |         |         |   |       |      
|Operating income                                                |                                    |   | 20,003  |         |   | 295   |       |   | 20,298  |        
|                                                                |                                    |   |         |         |   |       |       |  
|Other income (expense):                                         |                                    |   |         |         |   |       |       |   |         |        
|Interest and other income                                       |                                    |   |         |         |   |       |       |   | 323     |        
|Amortization of deferred loan costs                             |                                    |   |         |         |   |       |       |   | (407    | )      
|Interest expense                                                |                                    |   |         |         |   |       |       |   | (5,532  | )      
|                                                                |                                    |   |         |         |   |       |       |   |        
|                                                                | Total other income (expense)       |   |         |         |   |       |       |   |         | (5,616 
|                                                                |                                    |   |         |         |   |       |       |   |        
|Net income                                                      |                                    |   |         |         |   |       |       | $ | 14,682  |        
|                                                                |                                    |   |         |         |   |       |       |   |        
|For the Year Ended December 31, 2005                            |                                    |   |         |         |   |       |       |   |         |        
|Revenues                                                        |                                    | $ | 162,384 |         | $ | 4,217 |       | $ | 166,601 |        
|Operating costs and expenses:                                   |                                    |   |         |         |   |       |       |   |         |        
|Midstream purchases (exclusive of items shown separately below) |                                    |   | 133,089 |         |   |      |       |   | 133,089 |        
|Operations and maintenance                                      |                                    |   | 6,800   |         |   | 559   |       |   | 7,359   |        
|Depreciation and amortization                                   |                                    |   | 7,921   |         |   | 3,191 |       |   | 11,112  |        
|General and administrative expenses                             |                                    |   | 2,407   |         |   | 63    |       |   | 2,470   |        
|                                                                |                                    |   |         |         |   |       |      
|                                                                | Total operating costs and expenses |   |         | 150,217 |   |       | 3,813 |   |         | 154,030
|                                                                |                                    |   |         |         |   |       |      
|Operating income                                                |                                    |   | 12,167  |         |   | 404   |       |   | 12,571  |        
|                                                                |                                    |   |         |         |   |       |       |  
|Other income (expense):                                         |                                    |   |         |         |   |       |       |   |         |        
|Interest and other income                                       |                                    |   |         |         |   |       |       |   | 192     |        
|Amortization of deferred loan costs                             |                                    |   |         |         |   |       |       |   | (484    | )      
|Interest expense                                                |                                    |   |         |         |   |       |       |   | (1,942  | )      
|                                                                |                                    |   |         |         |   |       |       |   |        
|                                                                | Total other income (expense)       |   |         |         |   |       |       |   |         | (2,234 
|                                                                |                                    |   |         |         |   |       |       |   |        
|Net income                                                      |                                    |   |         |         |   |       |       | $ | 10,337  |        
|                                                                |                                    |   |         |         |   |       |       |   |        

F-37

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HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 11:  Selected Quarterly Financial DataUnaudited

The following is a summary of selected quarterly financial data for the years ended December 31, 2007 and 2006.

|                                            |  | 2007 Quarter
|------------------------------------------- |  | ------------
|
|Revenues                                    |  | $           
|Operating income                            |  |             
|Net income                                  |  |             
|General partner interest in net income      |  |             
|Limited partners' interest in net income    |  | $           
|Net income per limited partner unitbasic   |  | $           
|Net income per limited partner unitdiluted |  | $           

|
|

|                                            |  | 2006 Quarter
|------------------------------------------- |  | ------------
|
|Revenues                                    |  | $           
|Operating income                            |  |             
|Net income                                  |  |             
|General partner interest in net income      |  |             
|Limited partners' interest in net income    |  | $           
|Net income per limited partner unitbasic   |  | $           
|Net income per limited partner unitdiluted |  | $           

Note 12:  Net Income per Limited Partners' Unit

The computation of net income per limited partners' unit is based on the weighted-average number of common and subordinated units outstanding during the period.
Net income per unit applicable to limited partners is computed by dividing net income applicable to limited partners, after deducting the general partner's 2% interest and incentive distributions, and
after deducting net income attributable to the Predecessor (before February 15, 2005), by the weighted-average number of limited partnership units outstanding. The following is a reconciliation
of the limited partner units used in the

F-38

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HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 12:  Net Income per Limited Partners' Unit (Continued)

calculations
of income per limited partner unitbasic and income per limited partner unitdiluted assuming dilution for the years ended December 31, 2007, 2006 and 2005:

|                                                              |                                            | Income
Available to
Limited
Partners
(Numerator) |        | Limited
Partner Units
(Denominator) |           | Per Unit
Amount
|------------------------------------------------------------- | ------------------------------------------ | ------------------------------------------------ | ------ | ----------------------------------- | --------- | ---------------
|For the Year Ended December 31, 2007                          |                                            |                                                  |        |                                     |           |                
|Income per limited partner unitbasic:                        |                                            |                                                  |        |                                     |           |                
|                                                              | Income available to limited partners       |                                                  | $      | 6,258                               |           |                
|Weighted average limited partner units outstanding            |                                            |                                                  |        |                                     | 9,284,000 |                
|Income per limited partner unitdiluted:                      |                                            |                                                  |        |                                     |           |                
|                                                              | Unit Options, restricted and phantom units |                                                  |        |                                     |           | 50,000         
|                                                              |                                            |                                                  |        |                                     |           |                
|Income available to limited partners plus assumed conversions |                                            | $                                                | 6,258  |                                     | 9,334,000 |                
|                                                              |                                            |                                                  |        |                                     |           |                
|For the Year Ended December 31, 2006                          |                                            |                                                  |        |                                     |           |                
|Income per limited partner unitbasic:                        |                                            |                                                  |        |                                     |           |                
|                                                              | Income available to limited partners       |                                                  | $      | 12,273                              |           |                
|Weighted average limited partner units outstanding            |                                            |                                                  |        |                                     | 8,961,000 |                
|Income per limited partner unitdiluted:                      |                                            |                                                  |        |                                     |           |                
|                                                              | Unit Options and restricted units          |                                                  |        |                                     |           | 49,000         
|                                                              |                                            |                                                  |        |                                     |           |                
|Income available to limited partners plus assumed conversions |                                            | $                                                | 12,273 |                                     | 9,010,000 |                
|                                                              |                                            |                                                  |        |                                     |           |                
|For the Year Ended December 31, 2005                          |                                            |                                                  |        |                                     |           |                
|Income per limited partner unitbasic:                        |                                            |                                                  |        |                                     |           |                
|                                                              | Income available to limited partners       |                                                  | $      | 9,380                               |           |                
|Weighted average limited partner units outstanding            |                                            |                                                  |        |                                     | 7,034,000 |                
|Income per limited partner unitdiluted:                      |                                            |                                                  |        |                                     |           |                
|                                                              | Unit Options and restricted units          |                                                  |        |                                     |           | 52,000         
|                                                              |                                            |                                                  |        |                                     |           |                
|Income available to limited partners plus assumed conversions |                                            | $                                                | 9,380  |                                     | 7,086,000 |                
|                                                              |                                            |                                                  |        |                                     |           |                

Note 13:  Partners' Capital and Cash Distributions

Our unitholders (limited partners) have only limited voting rights on matters affecting our operations and activities and, therefore, limited ability to influence
our management's decisions regarding our business. Unitholders did not select our general partner or elect the board of directors of our general partner and effectively have no right to select our
general partner or elect its board of directors in the future. Unitholders' voting rights are further restricted by our partnership agreement provision providing that any units held by a person that
owns 20% or more of any class of units then outstanding, other than the general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of
directors of our general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our

F-39

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HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 13:  Partners' Capital and Cash Distributions (Continued)

unitholders
to call meetings or to acquire information about our operations, as well as other provisions limiting a unitholders' ability to influence the manner or direction of our management.

Our
Partnership Agreement requires that we distribute all of our cash on hand at the end of each quarter, less reserves established at our general partner's discretion. We refer to this
as "available cash." The amount of available cash may be greater than or less than the minimum quarterly distributions. In general, we will pay any cash distribution made each quarter in the following
manner:



If
cash distributions per unit exceed $0.495 in any quarter, our general partner will receive increasing percentages, up to a maximum of 50% of the cash we distribute in excess of that
amount. We refer to these distributions as "incentive distributions."

The
distributions on the subordinated units may be reduced or eliminated if necessary to ensure the common units receive their minimum quarterly distribution. Subordinated units will not
accrue arrearages. The subordination period will end once we meet certain financial tests, but not before March 31, 2010. These financial tests require us to have earned and paid the minimum
quarterly distribution on all of our outstanding units for three consecutive four-quarter periods. When the subordination period ends, all remaining subordinated units will convert into
common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

F-40

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HILAND PARTNERS, LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

December 31, 2007 and 2006

(in thousands, except unit information or unless otherwise noted)

Note 13:  Partners' Capital and Cash Distributions (Continued)

Cash
distributions paid by us to common and subordinated unitholders, including amounts paid to affiliate owners and regular and incentive distributions paid to our general partner for
2007 and 2006 were as follows (in thousands, except per unit amounts):

|         |     |   |        |  |   |        |  | General Partner |        | 
|-------- | --- | - | ------ |  | - | ------ |  | --------------- | ------ | 
|
|
|05/15/06 |     | $ | 0.6500 |  | $ | 2,858  |  | $               | 2,652  | 
|08/14/06 |     |   | 0.6750 |  |   | 3,485  |  |                 | 2,754  | 
|11/14/06 |     |   | 0.7000 |  |   | 3,623  |  |                 | 2,856  | 
|02/14/07 |     |   | 0.7125 |  |   | 3,694  |  |                 | 2,907  | 
|05/15/07 |     |   | 0.7125 |  |   | 3,724  |  |                 | 2,907  | 
|08/14/07 |     |   | 0.7325 |  |   | 3,837  |  |                 | 2,989  | 
|11/14/07 |     |   | 0.7550 |  |   | 3,959  |  |                 | 3,080  | 
|02/14/08 | (a) |   | 0.7950 |  |   | 4,168  |  |                 | 3,244  | 
|         |     |   |        |  |   |        |  |                 |        | 
|         |     | $ | 5.7325 |  | $ | 29,348 |  | $               | 23,389 | 
|         |     |   |        |  |   |        |  |                 |        | 

---

Note 14:  Subsequent Events (unaudited)

On February 6, 2008, we entered into a fourth amendment to our credit facility dated as of February 15, 2005. Pursuant to the fourth amendment, we
have, among other things, increased our borrowing base from $250 million, to $300 million and decreased the accordion feature in the facility from $100 million
to $50 million. Our original credit facility dated May 2005 was first amended in September 2005, amended a second time in June 2006 and amended a third time in July 2007.

The
fourth amendment increases our borrowing capacity under our senior secured revolving credit facility to $300 million such that the facility now consists of a
$291 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
"Acquisition Facility") and a $9.0 million senior secured revolving credit facility to be used for working capital and to fund distribution (the "Working Capital Facility").

In
addition, the fourth amendment provides for an accordion feature, which permits us, if certain conditions are met, to increase the size of the Acquisition Facility by up to
$50 million and allows for the issuance of letters of credit of up to $15 million in the aggregate. The senior secured revolving credit facility also requires us to meet certain
financial tests, including a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0 as of the last day of any fiscal quarter; provided that in the event that the Partnership makes certain
permitted acquisitions or capital expenditures, this ratio may be increased to 4.75:1.0 for the three fiscal quarters following the quarter in which such acquisition or capital expenditure occurs; and
a minimum interest coverage ratio of 3.0:1.0. The credit facility will mature in May 2011. At that time, the agreement will terminate and all outstanding amounts thereunder will be due and payable.

F-41

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