**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-K**

**x**                              ANNUAL REPORT PURSUANT TO SECTION 13OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934

**Forthe fiscal year ended December 31, 2006**

**Commission filenumber:  000-51120**

**Hiland Partners, LP**

(Exact name of Registrantas specified in its charter)

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

Registrant’stelephone number including area code**(580) 242-6040**

Securitiesregistered pursuant to Section 12(b) of the Act:

**Commonlimited partner units**

Securitiesregistered pursuant to Section 12(g) of the Act:

**None**

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofSecurities Act. Yes o No x

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 or15(d) of Act. Yes o No x

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes x No o

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment tothis Form 10-K. x

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

| Large accelerated  filer o |   | Accelerated filer x |   | Non-accelerated filer o |
|---------------------------------|--------|--------------------------|--------|------------------------------|

 

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

The aggregate market valueof common limited partner units held by non-affiliates of the registrant wasapproximately $182 million on June 30, 2006 based on the last sales priceas quoted on the Nasdaq National Market.

At March 5, 2007,there were 5,206,343 common units and 4,080,000 subordinated units outstanding.

DOCUMENTSINCORPORATED BY REFERENCE: **None**

 

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**TABLEOF CONTENTS**
| Items 1. and 2. |   | Business and Properties                                                                                             |   | 3  |
|-----------------|--------|---------------------------------------------------------------------------------------------------------------------|--------|----|
| Item 1A.        |   | Risk Factors                                                                                                        |   | 24 |
| Item 1B         |   | Unresolved Staff Comments                                                                                           |   | 41 |
| Item 3.         |   | Legal Proceedings                                                                                                   |   | 41 |
| Item 4.         |   | Submission of Matters to a Vote of Security Holders                                                                 |   | 41 |
| 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                                                         |   | 71 |
| Item 8.         |   | Financial Statements and Supplementary Data                                                                         |   | 73 |
| Item 9.         |   | Changes in and Disagreements on Accounting and  Financial Disclosure                                                |   | 73 |
| Item 9A.        |   | Controls and Procedures                                                                                             |   | 73 |
| Item 9B.        |   | Other Information                                                                                                   |   | 73 |
| Item 10.        |   | Directors and Executive Officers of the Registrant                                                                  |   | 74 |
| Item 11.        |   | Executive Compensation                                                                                              |   | 79 |
| Item 12.        |   | Security Ownership of Certain Beneficial Owners and  Management and Related Unitholder Matters                      |   | 90 |
| Item 13.        |   | Certain Relationships and Related Transactions                                                                      |   | 92 |
| Item 14.        |   | Principal Accountant Fees and Services                                                                              |   | 95 |
| Item 15.        |   | Exhibits and Financial Statement Schedules                                                                          |   | 96 |

 

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**PART I**

**Items 1. and 2.   Businessand Properties**

**Our Formation,Acquisitions and Public Offerings**

Hiland Partners, LP is a Delaware limited partnershipformed in October 2004 to own and operate the assets that had historicallybeen owned and operated by Continental Gas, Inc. (“CGI”) and HilandPartners, LLC.

CGI historically owned all of our natural gasgathering, processing, treating and fractionation assets other than our Worlandand Bakken gathering systems and certain systems acquired or constructed sinceour formation. Prior to July 21, 2004, CGI was owned by ContinentalResources, Inc. (“CRI”), an independent exploration and production companyowned by Harold Hamm, the Chairman of the Board of Directors of our generalpartner and the Harold Hamm DST and the Harold Hamm HJ Trusts, which are trustsestablished for the benefit of Harold Hamm’s children and which we refer toherein as the “Hamm Trusts.” On July 21, 2004, CRI completed the transferof CGI to Harold Hamm and the Hamm Trusts. Hiland Partners, LLC historicallyowned our Worland gathering system, our compression services assets and theBakken gathering system.

In connection with our initial public offering, theformer owners of CGI and Hiland Partners, LLC and certain of our affiliates,including our general partner, contributed to us all of the assets andoperations of CGI, other than a portion of its working capital assets, andsubstantially all of the assets and operations of Hiland Partners, LLC, otherthan a portion of its working capital assets and the assets related to theBakken gathering system, in exchange for an aggregate of 720,000 common unitsand 4,080,000 subordinated units, a 2% general partner interest in us and allof our incentive distribution rights, which entitle the general partner toincreasing percentages of the cash we distribute in excess of $0.495 per unitper quarter.

Effective September 1,2005, we purchased the outstanding membership interests in HilandPartners, LLC, the principal asset of which was the Bakken gathering system,for $92.7 million. We initiallyfinanced the acquisition from borrowings on our amended credit facility. On November 21,2005, we completed our second public offering, whereby we issued 1,630,000common units at an offering price of $41.77 per common unit. Proceeds totaled$66.1 million, net of the underwriter discount of $3.4 million. Offering costsincurred amounted to $0.6 million. We used $65.2 million of the net proceeds torepay a portion of credit facility borrowings we had used to acquire HilandPartners, LLC.

On May 1, 2006, we acquired the Kinta Areagathering assets from Enogex Gas Gathering, L.L.C., consisting of certaineastern Oklahoma gas gathering assets, for $96.4 million. We financed thisacquisition with $61.2 million of borrowings from our credit facility and $35.0million of proceeds from the issuance to Hiland Partners GP, LLC, our generalpartner, of 761,714 common units and 15,545 general partner equivalent units,both at $45.03 per unit.

On September 25, 2006, certain affiliatedunitholders contributed (i) all of the membership interests in our generalpartner, which owns the 2% general partner interest and all of the incentivedistribution rights in us and (ii) 1,301,471 common units (including761,714 common units held by our general partner) and 4,080,000 subordinatedunits in us to Hiland Holdings GP, LP, a publicly owned limited partnership (NASDAQ: HPGP), in exchange for 13,550,000 limitedpartner units, representing a 62.7% ownership in Hiland Holdings GP, LP. Hiland Partners GP Holdings, LLC, a Delawarelimited liability company formed on May 10, 2006, is the generalpartner of Hiland Holdings GP, LP.

References in this annualreport on Form 10-K to “Hiland Partners,” “we,” “our,” “us” orsimilar terms refer to Hiland Partners, LP and its operating subsidiaries aftergiving effect to the formation transactions described above. References to “HilandHoldings” refer to Hiland Holdings GP, LP.

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**Overview**

We are a growth-oriented midstream energy partnershipengaged in gathering, compressing, dehydrating, treating, processing andmarketing natural gas, and fractionating, or separating, natural gas liquids,or NGLs. We also provide air compression and water injection services to CRIfor use in its oil and gas secondary recovery operations. Our operations areprimarily located in the Mid-Continent and Rocky Mountain regions of the UnitedStates. In our midstream segment, we connect the wells of natural gas producersin our market areas to our gathering systems, treat natural gas to removeimpurities, process natural gas for the removal of NGLs, fractionate NGLs intoNGL products and provide an aggregate supply of natural gas and NGL products toa variety of natural gas transmission pipelines and markets. In our compressionsegment, we provide compressed air and water to CRI, an exploration andproduction company wholly owned by affiliates of our general partner. CRI usesthe compressed air and water in its oil and gas secondary recovery operationsin North Dakota by injecting them into its oil and gas reservoirs to increaseoil and gas production from those reservoirs. This increased production ofnatural gas flows through our midstream systems.

Our midstream assets consist of 13 natural gasgathering systems with approximately 1,844 miles of gas gatheringpipelines, five natural gas processing plants, three natural gas treatingfacilities and three NGL fractionation facilities. Our compression assetsconsist of two air compression facilities and a water injection plant.

We commenced our midstreamoperations in 1990 when CGI, then a subsidiary of CRI, constructed the EagleChief gathering system in northwest Oklahoma. Since 1990, we have grown througha combination of building gas gathering and processing assets in areas whereCRI has active exploration and production assets and through acquisitions ofexisting systems, which we have then expanded. Since inception, we haveconstructed 395 miles of natural gas gathering pipelines, three naturalgas processing plants, two treating facilities and one fractionation facility.In addition, our management team designed and constructed the Bakken gatheringsystem that we acquired from an affiliate of our general partner, whichcurrently consists of 334 miles of gas gathering pipeline, a natural gasprocessing plant, two compressor stations and one fractionation facility. Wehave also acquired 1,115 miles of natural gas gathering pipelines, one naturalgas processing plant, one treating facility and one fractionation facility. Ourtotal segment margin for the years ended December 31, 2006 and 2005 was$63.5 million and $33.5 million, respectively. Please read “—Non-GAAPFinancial Measures” for an explanation of total segment margin and areconciliation of total segment margin to its most directly comparablefinancial measure calculated and presented in accordance with generallyaccepted accounting principles, or GAAP.

**Recent Developments**

*Resignationof Randy Moeder.**  *OnMarch 14, 2007, we announced that Randy Moeder intends to resign as ChiefExecutive Officer and director of both our general partner and the generalpartner of Hiland Holdings GP, LP to pursue other career opportunities. Mr.Moeder has agreed to remain in such positions for approximately six months.Harold Hamm, Chairman of the board of directors of our general partner, isheading up a committee to secure a replacement for Mr. Moeder.

*RegistrationStatement.**  *OnJanuary 23, 2007 we, along with Hiland Partners Finance Corp., our whollyowned subsidiary, filed an S-3/A registration statement with theSecurities and Exchange Commission to register common unit and debt securitieswith a maximum aggregate offering price of $500.0 million. The securities wemay offer include common units representing limited partnership interests inus, and debt securities, which may be either senior debt securities orsubordinated debt securities.

*WoodfordShale Project.**  *OnDecember 12, 2006 we entered into an agreement to construct andoperate gathering pipelines and related facilities associated with thedevelopment of a portion of the 

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acreage owned by CRI inthe Woodford shale reserve in the Arkoma Basin of southeastern Oklahoma. Weplan to make an initial capital investment of approximately $13.0 million bythe end of 2007 and to invest an additional $10.0 million over the subsequentfour years to build a 40,000 Mcf/d refrigeration processing plant and installfield gathering, compression and associated equipment. The new gathering systemwill be designed to provide low-pressure and highly reliable gathering,compression and processing services. The gathering infrastructure is expectedto include more than 15,500 horsepower of compression to provide takeawaycapacity in excess of 40,000 Mcf/d. The agreement grants us the right toprocess the gas and further provides that we will receive certain fixed feesfor the dehydration, gathering and compression of the gas for an initial term of10 years. Expected startup of the initial phase of the project should occurduring the second quarter of 2007.

*Acquisitionof Kinta Area Gathering Assets.**  *On May 1, 2006, we acquiredcertain Kinta Area gathering assets from Enogex Gas Gathering, L.L.C. for$96.4 million, including certain closing costs. The acquisition wasprimarily financed with $61.2 million in borrowings under our creditfacility and the sale for $35.0 million of common units and generalpartner units to our general partner, as described below. The acquired assets,which are located in the eastern Oklahoma Arkoma Basin, have approximately 689wellhead receipt points and include five separate low pressure natural gasgathering systems consisting of 573 miles of natural gas gathering pipelinesthat were gathering approximately 134,000 Mcf/d as of December 31, 2006and 27 compressor units capable of over 40,500 horsepower of compression. Thenatural gas gathering systems operate under contracts with producers thatprovide for services under fixed-fee arrangements.

*EquityFinancing.**  *Topartially finance the acquisition of the Kinta Area gathering assets, on May 1,2006, we sold 761,714 common units and 15,545 general partner units to ourgeneral partner for $45.03 per unit, or $35.0 million in the aggregate.The purchase price was equal to the average closing price of our common unitsfor the three trading days immediately preceding May 1, 2006. Our generalpartner’s board of directors, as well as the conflicts committee of the boardof directors, consisting of two independent directors, approved thetransaction.

*BadlandsExpansion Project.**  *OnNovember 8, 2005, we entered into a new 15-year definitive gaspurchase agreement with CRI under which we will gather, treat and processadditional natural gas, which is produced as a by-product of CRI’s secondaryoil recovery operations, in the areas specified by the contract. In return, wewill receive 50% of the proceeds attributable to residue gas and natural gasliquids sales as well as a fixed fee of $0.20 per Mcf for gathering andtreating the natural gas, plus an additional $0.60 per Mcf fee for the first 36Bcf of natural gas gathered. Our general partner’s board of directors, as wellas the conflicts committee of the board, has approved the agreement.

In order to fulfill our obligations under theagreement, we are in the process of expanding our Badlands gas gathering systemand processing plant located in Bowman County, North Dakota. This expansionproject will include the construction of a 40,000 Mcf/d nitrogen rejectionplant, which is expected to be operational in the second quarter of 2007, andthe expansion of our existing Badlands field-gathering infrastructure. Weintend to invest approximately $40.0 million in the expansion project bythe second quarter of 2007, of which approximately $31.7 million had beeninvested as of December 31, 2006. We expect to invest an additional$9.5 million in 2007 on this project to expand the system.

On February 1, 2006, we entered into a five-yeardefinitive purchase agreement with a producer to build additional compressionfacilities and to expand our existing Badlands gas gathering system into SouthDakota. The gathering project was completed in the fourth quarter of 2006 at acost of $3.1 million, which was funded from borrowings on our bank creditfacility.

*OtherExpansion Projects.**  *Duringthe fourth quarter of 2006, we completed the construction a 25,000 Mcf/dnatural gas processing facility along our existing Matli gas gathering system.This new facility now processes the existing gas supply and provides additionalplant processing capacity for increased 

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system volumes. The$3.1 million investment in this expansion project was also funded fromborrowings on our bank credit facility.

In the fourth quarter of 2006, we completed theinstallation of additional gathering and compression infrastructure at ourBakken gathering system to increase the system’s capacity from approximately20,000 Mcf/d to 25,000 Mcf/d and are currently in the process of expandingthe existing NGL fractionation facilities at the processing plant tofractionate increased NGL volumes from both the Bakken processing plant and theBadlands processing plant.

In the first quarter of 2007 we completed theinstallation of additional pipelines and compression facilities at our EagleChief gathering system and increased our system capacity from approximately30,000 Mcf/d to approximately 35,500 Mcf/d due to increased volumes on thissystem.

We are in the process of installing fouramine-treating facilities at several of our Kinta Area gathering systemlocations to remove excess carbon dioxide levels from the natural gas. We arealso installing additional compression facilities to expand the currentcapacity by approximately 3,000 Mcf/d on these gathering systems. We will invest approximately $6.0 millionon these projects and expect that the treating facilities will be completed bythe end of the first quarter of 2007 and the compression facilities will becompleted by the end of the third quarter of 2007.

*Refinancingof Our Credit Facility.**  *On June 8, 2006, we amended our existing$125 million senior credit facility to, among other things, increase ourborrowing base to $200 million and revise certain covenants. For a morecomplete discussion of our credit facility, please see “Management’s Discussionand Analysis of Financial Condition and Results of Operations—Liquidity andCapital Resources—Credit Facility.”

*BoardMember Selections.**  *OnAugust 11, 2006, we announced that the board of directors of our generalpartner had appointed Mr. John T. McNabb, II and Dr. David L.Boren as directors. Mr. McNabb and Dr. Boren were named to theconflicts committee of the board of directors, with Mr. McNabb named tochair the committee. For a more complete description of the board of directorsof our general partner, please read “Management—Directors and ExecutiveOfficers of Hiland Partners GP, LLC.”

*Distribution Increase.**  *On January 25, 2007 wedeclared a cash distribution for the fourth quarter of 2006. The declaredquarterly distributions on our commonand subordinated units increased to $0.7125 per unit (an annualized rate of$2.85 per unit) from $0.70 per unit (an annualized rate of $2.80 per unit).This represents a 1.8% increase over the prior quarter and a 14.0% increaseover the distribution for the same quarter of the prior year. The distributionwas paid on February 14, 2007 to unitholders of record on February 5,2007. Under our partnership agreement, generally our general partner isentitled 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 theamount we distribute to each unitholder in excess of $0.5625 per unit perquarter up to $0.675 per unit per quarter and 50% of the excess over $0.675 perunit per quarter.

**Midstream Segment**

Our midstreamoperations consist of the following:

·       gathering and compressingnatural gas to facilitate its transportation to our processing plants, thirdparty pipelines, utilities and other consumers;

·       dehydrating natural gas toremove water from the natural gas stream to meet pipeline qualityspecifications;

·       treating natural gas toremove or reduce impurities such as carbon dioxide, hydrogen sulfide and othercontaminants to ensure that the natural gas meets pipeline qualityspecifications;

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·       processing natural gas toextract NGLs and selling the resulting residue natural gas and, in most cases, theNGLs; and

·       fractionating a portion ofour NGLs into a mix of NGL products, including ethane, propane and a mixture ofbutane and natural gasoline, and selling these NGL products to third parties.

Our midstreamassets include the following:

*·**      *Eagle Chief Gathering System.*  *The Eagle Chief gathering system isa 575-mile gas gathering system located in northwest Oklahoma thatgathers, compresses, dehydrates and processes natural gas. The system includesthe Eagle Chief processing plant and five compressor stations withapproximately 12,400 horsepower on the system. We constructed the Eagle Chiefgathering system in 1990 and constructed the Eagle Chief processing plant in1995. We acquired the Carmen gathering system in August 2003, whichconsists solely of gathering lines to expand our Eagle Chief gathering system.Our Eagle Chief gathering system has a capacity of 35,500 Mcf/d and averagethroughput was approximately 25,331 Mcf/d for the year ended December 31,2006. The system represented approximately 20.1% of our total segment marginfor the year ended December 31, 2006.

*·**      *Bakken Gathering System.*  *The Bakken gathering system is a 334-milegas gathering system located in Richland County, Montana that gathers,compresses, dehydrates and processes natural gas, and fractionates NGLs. Thissystem includes the Bakken processing plant, three compressor stations and onefractionation facility. The total system has approximately 10,600 horsepowerinstalled. We acquired the Bakken gathering system and the Bakken processingplant in September 2005. Our Bakken gathering system has capacity of25,000 Mcf/d and average throughput was approximately 17,290 Mcf/d for the yearended December 31, 2006. The system represented approximately 34.3% ofour total segment margin for the year ended December 31, 2006.

*·**      *Worland Gathering System.*  *The Worland gathering system is a151-mile gas gathering system located in central Wyoming that gathers,compresses, dehydrates, treats and processes natural gas, and fractionatesNGLs. The system includes the Worland processing plant, six compressorstations, one treating facility and one fractionation facility, with a totalinstalled horsepower of nearly 5,500. The Worland gathering system and theWorland processing plant were contributed to us on February 15, 2005 inconnection with our formation and our initial public offering. Our Worlandgathering system has a capacity of 8,000 Mcf/d and average throughput wasapproximately 2,759 Mcf/d for the year ended December 31, 2006. Thesystem represented approximately 6.9% of our total segment margin for the yearended December 31, 2006.

*·**      *Badlands Gathering System.*  *The Badlands gathering system is a141-mile gas gathering system with about 5,900 horsepower located insouthwest North Dakota that gathers, compresses, dehydrates, treats andprocesses natural gas, and fractionates NGLs. The system includes the Badlandsprocessing plant, five compressor stations, one treating facility and onefractionation facility. We constructed the Badlands gathering system and theBadlands processing plant in 1997. Our Badlands gathering system has a capacityof 5,000 Mcf/d and average throughput was approximately 2,489 Mcf/d for theyear ended December 31, 2006. The system represented approximately 8.8% ofour total segment margin for the year ended December 31, 2006.

*·**      *Matli Gathering System.*  *The Matli gathering system is a 52-milegas gathering system located in central Oklahoma that gathers, compresses,dehydrates, treats and processes natural gas. The system includes the Matliprocessing plant, two compressor stations and one treating facility whichcombined have approximately 6,950 horsepower. We constructed the Matligathering system in 1999 and in December 2006 we completed theconstruction of a new processing plant. Our Matli gathering system has acapacity of 25,000 Mcf/d and average throughput was approximately 

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15,231 Mcf/d for theyear ended December 31, 2006. The system represented approximately 5.0% ofour total segment margin for the year ended December 31, 2006.

*·**      *Kinta Area Gathering Systems.*  *The Kinta Area gathering systems weacquired on May 1, 2006 include five separate low pressure natural gasgathering systems located in the eastern Oklahoma Arkoma Basin covering573 miles of natural gas gathering pipelines. The systems include twelvecompressor stations, which are comprised of 27 units with an aggregate ofapproximately 40,500 horsepower. Our Kinta Area gathering systems have anaggregate capacity of 180,000 Mcf/d and average throughput was approximately134,140 Mcf/d from May 1, 2006 to December 31, 2006. The systemsrepresented approximately 16.4% of our total segment margin for the year ended December 31,2006.

*·**      *Other Systems.*  *We also own three natural gasgathering systems located in Texas, Mississippi and Oklahoma. These systemsrepresented approximately 0.9% of our total segment margin for the year ended December 31,2006.

Thefollowing table contains certain information regarding our gathering systems asof or for the year ended December 31, 2006.

| ** **                      | ** ** | ** **                       | ** ** | ** **  | ** ** | ** **    | ** ** | ** **      | ** ** | ** **        | ** ** | ** **           | ** ** | **Percent**       | ** ** |
|---------------------------------|------------|----------------------------------|------------|-------------|------------|---------------|------------|-----------------|------------|-------------------|------------|----------------------|------------|-------------------|------------|
| ** **                      | ** ** | ** **                       | ** ** | ** **  | ** ** | ** **    | ** ** | ** **      | ** ** | ** **        | ** ** | ** **           | ** ** | **of Total** | ** ** |
| ** **                      | ** ** | ** **                       | ** ** | **Length**  | ** ** | **Wells**     | ** ** | **Throughput**  | ** ** | **Average**       | ** ** | **Utilization**      | ** ** | **Segment**       | ** ** |
| **Asset**                       | ** ** | **Type**                         | ** ** | **(Miles)** | ** ** | **Connected** | ** ** | **Capacity(1)** | ** ** | **Throughput(1)** | ** ** | **of Capacity** | ** ** | **Margin**        | ** ** |
| Eagle Chief gathering system    |       | Gathering  pipelines             |       |        | 575        |          |       |            | 423        |              |       |                 | 30,000     |              |       |   | 25,331 |   |   |   | 84.4 | % |   |   |   |   |   |
|                            |       | Processing  plant                |       |        | —     |          |       |            | —     |              |       |                 | 35,000     |              |       |   | 25,331 |   |   |   | 72.4 | % |   |   | 20.1 | % |   |
| Bakken gathering system         |       | Gathering  pipelines             |       |        | 334        |          |       |            | 224        |              |       |                 | 25,000     |              |       |   | 17,290 |   |   |   | 69.2 | % |   |   |   |   |   |
|                            |       | Processing  plant                |       |        | —     |          |       |            | —     |              |       |                 | 25,000     |              |       |   | 17,290 |   |   |   | 69.2 | % |   |   |   |   |   |
|                            |       | Fractionation  facility (Bbls/d) |       |        | —     |          |       |            | —     |              |       |                 | 4,600      |              |       |   | 2,646 |   |   |   | 57.5 | % |   |   | 34.3 | % |   |
| Worland gathering system        |       | Gathering  pipelines             |       |        | 151        |          |       |            | 94         |              |       |                 | 8,000      |              |       |   | 2,759 |   |   |   | 34.5 | % |   |   |   |   |   |
|                            |       | Processing  plant                |       |        | —     |          |       |            | —     |              |       |                 | 8,000      |              |       |   | 2,759 |   |   |   | 34.5 | % |   |   |   |   |   |
|                            |       | Treating  facility               |       |        | —     |          |       |            | —     |              |       |                 | 8,000      |              |       |   | 2,759 |   |   |   | 34.5 | % |   |   |   |   |   |
|                            |       | Fractionation  facility (Bbls/d) |       |        | —     |          |       |            | —     |              |       |                 | 650        |              |       |   | 299 |   |   |   | 46.0 | % |   |   | 6.9 | % |   |
| Badlands gathering system       |       | Gathering  pipelines             |       |        | 141        |          |       |            | 106        |              |       |                 | 5,000      |              |       |   | 2,489 |   |   |   | 49.8 | % |   |   |   |   |   |
|                            |       | Processing  plant                |       |        | —     |          |       |            | —     |              |       |                 | 5,000      |              |       |   | 2,489 |   |   |   | 49.8 | % |   |   |   |   |   |
|                            |       | Treating  facility               |       |        | —     |          |       |            | —     |              |       |                 | 7,100      |              |       |   | 2,489 |   |   |   | 35.1 | % |   |   |   |   |   |
|                            |       | Fractionation  facility (Bbls/d) |       |        | —     |          |       |            | —     |              |       |                 | 600        |              |       |   | 312 |   |   |   | 52.0 | % |   |   | 8.8 | % |   |
| Matli gathering system          |       | Gathering  pipelines             |       |        | 52         |          |       |            | 48         |              |       |                 | 25,000     |              |       |   | 15,231 |   |   |   | 60.9 | % |   |   |   |   |   |
|                            |       | Processing  plant                |       |        | —     |          |       |            | —     |              |       |                 | 25,000     |              |       |   | 8,986 |   |   |   | 35.9 | % |   |   |   |   |   |
|                            |       | Treating  facility               |       |        | —     |          |       |            | —     |              |       |                 | 20,000     |              |       |   | 8,686 |   |   |   | 43.4 | % |   |   | 5.0 | % |   |
| Kinta Area gathering systems(2) |       | Gathering  pipelines             |       |        | 573        |          |       |            | 689        |              |       |                 | 180,000    |              |       |   | 134,140 |   |   |   | 74.5 | % |   |   | 16.4 | % |   |
| Other Systems                   |       | Gathering  pipelines             |       |        | 18         |          |       |            | 33         |              |       |                 | 7,000      |              |       |   | 2,531 |   |   |   | 36.2 | % |   |   | 0.9 | % |   |
|                            |       | Total                            |       |        | 1,844      |          |       |            | 1,617      |              |       |                 |       |              |       |   |   |   |   |   |   |   |   |   | 92.4 | % |   |

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(1)             Throughput capacity and average throughput are measuredin Mcf/d for the gathering pipelines, processing plants and treating facilitiesand in Bbls/d for the fractionation facilities shown on this chart.

(2)             The Kinta Area gathering systems were acquired on May 1,2006. As such, the systems’ average throughput is computed from the effectivedate to December 31, 2006.

**Compression Segment**

We provide air and watercompression services to CRI for use in its oil and gas secondary recoveryoperations under a four-year, fixed-fee contract (which we entered into inconnection with our initial public offering) at our Cedar Hills compressionfacility, our Horse Creek compression facility and our water injection plantlocated next to our Cedar Hills compression facility. These assets are locatedin North 

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Dakotain close proximity to our Badlands gathering system. At the compressionfacilities, we compress air to pressures in excess of 4,000 pounds per squareinch, and at the water injection plant, we pump water to pressures in excess of2,000 pounds per square inch. The air and water are delivered at the tailgateof our facilities into pipelines operated by CRI and are ultimately utilized byCRI in its oil and gas secondary operations. The natural gas produced by CRIflows through our Badlands gathering system. Our compression segmentrepresented approximately 7.6% of our total segment margin for the year ended December 31,2006.

**FinancialInformation About Segments**

See Part II, Item 8—FinancialStatements and Supplementary Data.

**CompetitiveStrengths**

Based on the followingcompetitive strengths, we believe that we are well positioned to compete in ouroperating regions:

*·**      *We have expertise in developing midstreamsystems.*  *Since ourinception in 1990, we have demonstrated the ability to identify midstreamopportunities and build or acquire the assets needed to capitalize on thoseopportunities. To date, we have built or acquired nine gas gathering systems. Amajority of our growth has come from gas gathering systems and plants that wehave constructed, including the Eagle Chief, Bakken, Badlands and Matligathering systems. Since building the Eagle Chief gathering system, we haveexpanded that system by constructing 198 miles of gathering pipeline andacquiring approximately 377 miles of gathering pipeline in five separatetransactions. We have also utilized acquisitions such as our purchases of the569-mile Kinta Area gathering assets located in eastern Oklahoma on May 1,2006 and the 151-mile Worland gathering system in 2000 as a way toestablish presence in new areas.

*·**      *Substantially all of our facilities aremodern.*  *We built ourEagle Chief processing plant in 1995, our Badlands processing plant in 1997 andour new Matli processing plant in 2006. In addition, the previous ownerreplaced a substantial portion of the equipment on our Worland gatheringsystem, including the Worland processing plant and the fractionation facilityin 1997. Our Bakken gathering system was constructed in 2004. Our $49.5 millionexpansion at our Badlands location will be completed in 2007. The condition ofour facilities directly benefits our margins and our ability to attract newsupplies of natural gas by offering operational efficiency and reliability. Ourfacilities generally require less maintenance and are subject to fewerenvironmental liabilities and permitting issues than older facilities.

*·**      *Our assets are strategically located inmajor natural gas supply areas and have available capacity.*  *Our assets are strategicallylocated in the Mid-Continent and Rocky Mountain regions of the United States.These regions are generally characterized by significant current drillingactivity, which provides us with attractive opportunities to access newly developednatural gas supplies. Several of these regions continue to experience increasedlevels of exploration, development and production activities as a result offavorable commodity prices, new discoveries and the implementation of secondaryrecovery techniques. In addition, substantially all of our assets haveavailable capacity. We believe that our presence in these regions, togetherwith the available capacity of our assets and limited competitive alternatives,provides us with a competitive advantage in capturing new supplies of naturalgas.

*·**      *We provide an integrated and comprehensivepackage of midstream services.*  *Weprovide a broad range of midstream services to natural gas producers, includingnatural gas gathering, compression, dehydration, treating, processing andmarketing and the fractionation of NGLs. We believe our ability to provide allof these services gives us an advantage in competing for new supplies ofnatural 

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gas because we can provideall of the services producers, marketers and others require to connect theirnatural gas quickly and efficiently.

*·**      *We have the financialflexibility to pursue growth projects.*  *Our$200.0 million bank credit facility contains a $191.0 millionrevolving facility for acquisitions and capital expenditures, of whichapproximately $43.9 million is available as of December 31, 2006, anda $9.0 million working capital facility. We believe the available capacityunder our credit facility combined with our expected ability to access thecapital markets will provide us with a flexible financial structure that willfacilitate our strategic expansion and acquisition strategies.

**Business Strategies**

We are committed toincreasing the amount of cash available for distribution per unit by executingthe following strategies:

*·**      *Engaging in construction and expansionopportunities.*  *Weintend to leverage our existing infrastructure and customer relationships byconstructing and expanding systems to meet new or increased demand for ourmidstream services. These projects include expansion of existing systems andconstruction of new facilities, such as our Badlands expansion project and ourWoodford Shale project.

*·**      *Pursuing complementary acquisitions.*  *We intend to make complementaryacquisitions of midstream assets in our operating areas that provideopportunities to expand or increase the utilization of our existing assets. Weintend to pursue acquisitions that we believe will allow us to capitalize onour existing infrastructure, personnel, and producer and customer relationshipsto provide an integrated package of services. In addition, we may pursueselected acquisitions in new geographic areas to the extent they present growthopportunities similar to those we are pursuing in our existing areas ofoperations.

*·**      *Increasing volumes on our existing assets.*  *Our gathering systems have excesscapacity, which provides us with opportunities to increase throughput volumewith minimal incremental costs and thereby increase cash flow. We intend toaggressively market our services to producers in order to connect new suppliesof natural gas, increase volumes and more fully utilize our capacity,particularly in our areas experiencing an increased level of natural gasexploration, development and production activities.

*·**      *Taking measures thatreduce our exposure to commodity price risk.*  *Because of the significant volatility of natural gasand NGL prices, we attempt to operate our business in a manner that allows usto mitigate the impact of fluctuations in commodity prices. In order to reduceour exposure to commodity price risk, we intend to pursue fee-basedarrangements, where market conditions permit, and to enter into forward salescontracts or hedging arrangements to cover a portion of our operations that arenot conducted under fee-based arrangements. In addition, when processing margins(or the difference between NGL sales prices and the cost of natural gas) areunfavorable, we can elect not to process natural gas at our Eagle Chiefprocessing plant and deliver the unprocessed natural gas directly into theinterstate pipeline. Collectively, these strategies should contribute to morestable cash flows.

**Midstream Assets**

Our natural gas gatheringsystems include approximately 1,844 miles of pipeline. A substantial majorityof our revenues are derived from gathering, compressing, dehydrating, treating,processing and marketing the natural gas that flows through our gatheringpipelines and from fractionating NGLs resulting from the processing of naturalgas into NGL products. We describe our principal systems below.

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***Eagle Chief Gathering System***

*General.**  *The Eagle Chief gathering system islocated in northwest Oklahoma and consists of approximately 575 miles ofnatural gas gathering pipelines, ranging from two inches to sixteen inches indiameter, and the Eagle Chief processing plant. The gathering system has acapacity of approximately 30,000 Mcf/d, and average throughput wasapproximately 25,331 Mcf/d for the year ended December 31, 2006. There arefive gas compressor stations located within the gathering system, comprised oftwelve units. The plant and compressor stations combined have an aggregate ofapproximately 12,400 horsepower.

We completed construction and commenced operation ofthe Eagle Chief gathering system in 1990 and constructed the Eagle Chiefprocessing plant in 1995. Since its construction, we have expanded the size ofthe Eagle Chief gathering system through the acquisition of approximately 377miles of gathering pipelines in five separate acquisitions, including ouracquisition of the Carmen gathering system, and the construction ofapproximately 198 miles of gathering pipelines. In the first quarter of 2007,we completed the installation of additional pipelines and compressionfacilities at our Eagle Chief gathering system and increased our current systemcapacity from approximately 30,000 Mcf/d to approximately 35,500 Mcf/d.

The Eagle Chief processing plant processes natural gasthat flows through the Eagle Chief gathering system to produce residue gas andNGLs. The natural gas gathered in this system is lean gas that, depending ondelivery points, may not be required to be processed to meet pipeline qualityspecifications when we sell into interstate markets. The plant has processingcapacity of approximately 35,000 Mcf/d. During the year ended December 31,2006, the facility processed approximately 25,331 Mcf/d of natural gas andproduced approximately 864 Bbls/d of NGLs.

*NaturalGas Supply.**  *Asof December 31, 2006, 423 wells were connected to our Eagle Chiefgathering system. These wells are located in the Anadarko Basin of northwesternOklahoma and we believe they generally have long lives. The primary suppliersof natural gas to the Eagle Chief gathering system are Chesapeake EnergyCorporation and CRI, which represented approximately 65% and 11%, respectively,of the Eagle Chief gathering system’s natural gas supply for the year ended December 31,2006.

The natural gas supplied to the Eagle Chief gatheringsystem is generally dedicated to us under individually negotiated long-termcontracts. Some of our contracts have an initial term of five years. Followingthe initial term, these contracts generally continue on a year-to-year basisunless terminated by one of the producers. In addition, some of our contractsare for the life of the lease. Natural gas is purchased at the wellhead fromthe producers under percentage-of-proceeds contracts, percentage-of-indexcontracts or fee-based contracts. For the year ended December 31, 2006,approximately 62%, 35% and 3% of our total segment margin attributable to theEagle Chief gathering system was derived from percentage-of-proceeds,percentage-of-index and fee-based contracts, respectively. For a more completediscussion of our natural gas purchase contracts, please read “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Our Natural Gas Purchase Contracts.”

Our Eagle Chief gathering system is located in anactive drilling area. This area has experienced increased levels of natural gasexploration, development and production activities as a result of higherrealized natural gas prices, new discoveries and the implementation of newexploration and production techniques. For example, our average throughput atthe Eagle Chief gathering system increased from 16,900 Mcf/d for December 2003to 25,331 Mcf/d for December 2006. During the year ended December 31,2006, we added 51 wells to our system. We believe that this higher level ofexploration and development activity in this area will continue and that manyof the producers drilling in the area will choose to use our midstream naturalgas services due to our excess capacity in this system and limited competitivealternatives.

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*Marketsfor Sale of Natural Gas and NGLs.**  *The Eagle Chief gathering systemhas numerous market outlets for the natural gas that we gather and NGLs that weproduce on the system. The residue gas is sold at the tailgate of the EagleChief processing plant on the Oklahoma Gas Transportation pipeline tointrastate markets and on the Panhandle Eastern Pipeline Company pipeline tointerstate markets. Because the area connected to our Eagle Chief gatheringsystem produces lean natural gas, we are able to bypass our Eagle Chiefprocessing plant by selling into the interstate markets when processing marginsare unfavorable. The NGLs extracted from the gas at the Eagle Chief processingplant are transported by pipeline to ONEOK Hydrocarbon Company’s Medfordfacility for fractionation. We are currently selling the NGLs to ONEOKHydrocarbon under a year-to-year contract.

Our primary purchasers ofresidue gas and NGLs on the Eagle Chief gathering system were OGE EnergyResources, Inc., ONEOK Hydrocarbon, LP, Chevron Natural Gas andBP Energy Company, which represented approximately 29%, 20%, 18% and 18%,respectively, of the revenues from such sales for the year endedDecember 31, 2006.

***Bakken Gathering System***

*General.**  *The Bakken gathering system islocated in eastern Montana and consists of approximately 334 miles of naturalgas gathering pipelines, ranging from three inches to twelve inches indiameter, the Bakken processing plant, which includes seven compressors and afractionation facility. The gathering system has a capacity of approximately25,000 Mcf/d, and average throughput was approximately 17,290 Mcf/d forthe year ended December 31, 2006. There are three gas compressor stationslocated within the gathering system, comprised of five units. The compressorstations and plant combined have slightly over 10,600 horsepower.

We acquired the Bakken gathering system in September 2005in connection with our acquisition of Hiland Partners, LLC. The Bakkengathering system, including the Bakken processing plant, was constructed during2004 and commenced operations on November 8, 2004.

The Bakken processing plant processes natural gas thatflows through the Bakken gathering system to produce residue gas and NGLs. Theplant has processing capacity of approximately 25,000 Mcf/d. For the year endedDecember 31, 2006, the facility processed approximately 17,290 Mcf/d ofnatural gas and produced approximately 1,742 Bbls/d of NGLs.

The Bakken gathering system also includes a fractionationfacility that separates NGLs into propane and a mixture of butane and gasoline.The fractionation facility has a capacity to fractionate approximately 4,600Bbls/d of NGLs. For the year ended December 31, 2006, the facilityfractionated an average of approximately 2,646 Bbls/d to produce approximately974 Bbls/d of propane and approximately 724 Bbls/d of a mixture of butane andgasoline. In connection with the expansion of the gathering and compressioninfrastructure we completed in the fourth quarter of 2006 in which we increasedthe system’s capacity from approximately 20,000 Mcf/d to 25,000 Mcf/d, wefurther intend to expand the existing NGL fractionation facilities at ourBakken processing plant in order to fractionate expected increased NGL volumesfrom both the Bakken processing plant and the Badlands processing plant. Weexpect this expansion will be completed in the second quarter of 2007.

*NaturalGas Supply.**  *Asof December 31, 2006, 224 wells were connected to our Bakken gatheringsystem. These wells, which are located in the Williston Basin of Montana,primarily produce crude oil from the Bakken formation. The associated naturalgas produced from these wells flows through our Bakken gathering system. Theprimary suppliers of natural gas to the Bakken gathering system are EnerplusResources (USA) Corporation, CRI and Burlington Resources Trading, Inc.,which represented approximately 48%, 40% and 12%, respectively, of the Bakkengathering system’s natural gas supply for the year ended December 31,2006.

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Substantially all of the natural gas supplied to theBakken gathering system is dedicated to us under three individually negotiatedpercentage-of-proceeds contracts. Two of these contracts have an initial termof 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 morecomplete discussion of our natural gas purchase contracts, please read “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Our Natural Gas Purchase Contracts.”

Our Bakken gathering system is located in an activedrilling area. During the year ended December 31, 2006, we added 81 wellsto our system. We believe that this higher level of exploration and developmentactivity in this area will continue and that many of the producers drilling inthe area will choose to use our midstream natural gas services due to our excesscapacity in this system and limited competitive alternatives.

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas derived from ourprocessing operations is sold at the tailgate of the Bakken processing plant onthe Williston Basin Intrastate Pipeline to intrastate markets. We sell thepropane that is produced by our fractionation facility and the remaining NGLproducts to SemStream, L.P. at the tailgate of the plant.

Our primary purchasers ofresidue gas and NGLs on the Bakken gathering system were Montana-DakotaUtilities Company and SemStream, L.P., which represented approximately 51%, and43% respectively, of the revenues from such sales for the year ended December 31,2006.

***Worland Gathering System***

*General.**  *The Worland gathering system islocated in central Wyoming and consists of approximately 151 miles of naturalgas gathering pipelines, ranging from two inches to eight inches in diameter,the Worland processing plant, a natural gas treating facility and afractionation facility. The gathering system has a capacity of approximately8,000 Mcf/d, and average throughput was approximately 2,759 Mcf/d for the yearended December 31, 2006. There are seven gas compressor stations locatedwithin the gathering system, comprised of eleven units. The plant andcompressor stations have a total of nearly 5,500 horsepower installed.

The Worland gathering system and the Worlandprocessing plant were contributed to us on February 15, 2005 in connectionwith 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 fractionationfacility, was replaced in 1997.

The Worland processing plant processes natural gasthat flows through the Worland gathering system to produce residue gas andNGLs. The natural gas gathered in this system is rich gas that must be processedin order to meet pipeline quality specifications. The plant has processingcapacity of approximately8,000 Mcf/d. During the year ended December 31, 2006, the facilityprocessed approximately 2,759 Mcf/d of natural gas and produced approximately156 Bbls/d of NGLs.

The Worland gathering system includes a natural gasamine treating facility that removes carbon dioxide and hydrogen sulfide fromnatural gas that is gathered into our system before the natural gas isintroduced to transportation pipelines to ensure that it meets pipeline qualityspecifications. Generally, the natural gas gathered in this system contains ahigh concentration of hydrogen sulfide, a highly toxic and corrosive chemicalthat must be removed prior to transporting the gas via pipeline. Our Worlandtreating facility has a circulation capacity of 70 gallons per minute andthroughput capacity of 8,000 Mcf/d.

The Worland gathering system also includes afractionation facility that separates NGLs into propane and a mixture of butaneand gasoline. The fractionation facility has a capacity to fractionateapproximately 650 Bbls/d of NGLs. For the year ended December 31, 2006,the facility fractionated an average of 

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approximately 299 Bbls/dto produce approximately 54 Bbls/d of propane and approximately 63 Bbls/d of amixture of butane and gasoline.

*NaturalGas Supply.**  *Asof December 31, 2006, 94 wells were connected to our Worland gatheringsystem. These wells are located in the Bighorn Basin of central Wyoming andgenerally have long lives with predictable and steady flow rates. The primarysuppliers of natural gas to the Worland gathering system are CRI and KCSResources, Inc., which represented approximately 61% and 30%,respectively, of the Worland gathering system’s natural gas supply for the yearended December 31, 2006.

The natural gas supplied to the Worland gatheringsystem is generally dedicated to us under individually negotiated long-termcontracts. Following the initial term of the contracts, they generally continueon a year to year basis, unless terminated by one of the producers. Natural gasis purchased at the wellhead from the producers under percentage-of-indexcontracts and fixed fee contracts. For the year ended December 31, 2006,approximately 94% and 6% of our total segment margin attributable to theWorland gathering system was derived from percentage-of-index contracts andfixed fee contracts, respectively. For a more complete discussion of ournatural gas purchase contracts, please read “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Our Contracts—OurNatural Gas Purchase Contracts.”

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas derived from ourprocessing operations is sold at the tailgate of the Worland processing planton the Williston Basin Intrastate Pipeline to intrastate markets. We sell thepropane that is produced by our fractionation facility and the remaining NGLproducts to a subsidiary of Kinder Morgan Energy Partners, L.P. at the tailgateof the plant.

Our primary purchasers ofresidue gas and NGLs on the Worland gathering system were Rainbow Gas Company,a Kinder Morgan Energy Partners, L.P. subsidiary and Tenaska MarketingVentures, which represented approximately 29%, 28% and 28%, respectively, ofrevenues from such sales on the Worland gathering system for the year ended December 31,2006.

***Badlands Gathering System[ and Air Compression andWater Injection Facilities***

*General.**  *The Badlands gathering system islocated in southwestern North Dakota and consists of approximately 141 miles ofnatural gas gathering pipelines, ranging from two inches to eight inches indiameter, the Badlands processing plant, a natural gas treating facility, afractionation facility  and five gascompressor stations. The total horsepower for the system was about 5,900 at theend of 2006. The gathering system has a capacity of approximately 5,000 Mcf/d,and average throughput was approximately 2,489 Mcf/d for the year ended December 31,2006.

We completed construction and commenced operation ofthe Badlands gathering system, including the Badlands processing plant, in1997. The Badlands processing plant processes natural gas that flows throughthe Badlands gathering system to produce residue gas and NGLs. The natural gasgathered in this system is rich gas that must be processed in order to meetpipelines quality specifications. The plant has processing capacity ofapproximately 5,000 Mcf/d. During the year ended December 31, 2006, thefacility processed approximately 2,489 Mcf/d of natural gas and producedapproximately 270 Bbls/d of NGLs.

The Badlands gathering system includes a natural gastreating facility that uses a solid chemical to remove hydrogen sulfide fromnatural gas that is gathered into our system before the natural gas isintroduced to transportation pipelines to ensure it meets pipeline qualityspecifications. Our Badlands treating facility has throughput capacity of 7,100Mcf/d.

The Badlands gathering system also includes afractionation facility that separates NGLs into propane and a mixture of butaneand gasoline. The fractionation facility has a capacity to fractionateapproximately 600 Bbls/d of NGLs. For the year ended December 31, 2006,the facility fractionated an average of 

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approximately 312 Bbls/dto produce approximately 95 Bbls/d of propane and approximately 114 Bbls/d of amixture of butane and gasoline.

On February 1, 2006, we entered into a five-yeardefinitive purchase agreement with a current producer to build additionalcompression facilities and to expand our existing gas gathering system intoSouth Dakota. The gathering project was completed in the fourth quarter of 2006at a cost of $3.1 million, whichwe funded using our existing bank credit facility.

On November 8, 2005, we entered into a new 15-yeardefinitive gas purchase agreement with CRI under which we will gather, treatand process additional natural gas, which is produced as a by-product of CRI’ssecondary oil recovery operations, in the areas specified by the contract. Inorder to fulfill our obligations under the agreement, we intend to expand ourBadlands gas gathering system and processing plant located in Bowman County,North Dakota. This expansion project will include the construction of a40,000 Mcf/d nitrogen rejection plant and the expansion of our existingBadlands field gathering infrastructure. The expansion project, targeted forcompletion in the second quarter of 2007, is expected to cost approximately$40.0 million, with an additional investment of $9.5 million plannedduring the second half of 2007 to expand the system. We are funding thisproject using our existing bank credit facility, and as of December 31,2006, we have invested approximately $31.7 million.

*NaturalGas Supply.**  *Asof December 31, 2006, 106 wells were connected to our Badlands gatheringsystem. These wells are located in the Williston Basin of southwestern NorthDakota and northwestern South Dakota and generally have long lives withpredictable and steady flow rates. The primary suppliers of natural gas to theBadlands gathering system are CRI, Luff Exploration Company and BurlingtonResources, which represented approximately 44%, 28% and 21%, respectively, ofthe Badlands gathering system’s natural gas supply for the year ended December 31,2006.

The natural gas supplied to the Badlands gatheringsystem is generally dedicated to us under individually negotiated long-termcontracts. Our new agreement with CRI has an initial term of 15 years.Under this agreement, we will receive 50% of the proceeds attributable toresidue gas and natural gas liquids sales as well as certain fixed fees associatedwith gathering and treating the natural gas, including a $0.60 per Mcf fee forthe first 36.0 Bcf of natural gas gathered. This agreement will replace ourexisting agreement with CRI in the area when the new plant becomes operational.Following the initial term of the contracts, they generally continue on a yearto year basis, unless terminated by one of the producers. For these otheragreements, natural gas is purchased at the wellhead from the producers underpercentage-of-index arrangements. For a more complete discussion of our naturalgas purchase contracts, please read “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations—Our Contracts—Our Natural GasPurchase Contracts.”

*AirCompression and Water Injection Facilities.**  *We believe that our Badlandsgathering system is strategically located in an area where secondary recoveryoperations may provide us with additional natural gas supplies. In order toenhance the production of natural gas that flows through our Badlands gatheringsystem, we currently provide air compression and water injection services toCRI under long-term contracts at our Cedar Hills compression facility, ourHorse Creek compression facility and our water injection Plant, all of whichare located in North Dakota in close proximity to our Badlands gatheringsystem. For a description of these services, please read “—Compression Assets.”

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas derived from ourprocessing operations is sold at the tailgate of the Badlands processing plantto end users or on the Williston Basin Intrastate Pipeline located at thetailgate of the plant. We sell the propane that is produced by ourfractionation facility and the remaining NGL products to SemStream, L.P. at thetailgate of the plant.

Our primary purchasers ofthe residue gas, propane and NGLs from the Badlands gathering system were CRI,SemStream, L.P. and a Kinder Morgan Energy Partners, L.P. subsidiary, whichrepresented 

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approximately33%, 28% and 27%, respectively, of the revenues from such sales for the yearended December 31, 2006.

***Matli Gathering System***

*General.**  *The Matli Gathering System islocated in central Oklahoma and consists of approximately 52 miles of naturalgas gathering pipelines, ranging from three inches to twelve inches indiameter, the Matli processing plant, and a natural gas treating facility andtwo gas compressor stations, all totaling approximately 6,950 horsepower. Thegathering system has a capacity of approximately 25,000 Mcf/d, and averagethroughput was approximately 15,231 Mcf/d for the year ended December 31,2006.

We commenced operation of theMatli gathering system in 1999. During the fourth quarter of 2006, wecompleted the construction of a 25,000 Mcf/d natural gas processing facility along our existing gasgathering system, which replaced our10,000 Mcf/d processing facility we had constructed in 2003. The Matliprocessing plant processes natural gas on the Matli gathering system to produceresidue gas and NGLs. The natural gas gathered in this system must be processedin order to meet pipeline quality specifications, but is relatively lean gas.The new plant has processing capacity of approximately 25,000 Mcf/d.During the year ended December 31, 2006, the facilities processedapproximately 8,986 Mcf/d of natural gas and produced approximately 216Bbls/d of NGLs. The $3.1 million investment in the new processing facilitywas funded from borrowings on our bank credit facility.

The Matli gathering system includes a natural gastreating facility that uses a liquid chemical to remove hydrogen sulfide fromnatural gas that is gathered into our system before the natural gas isintroduced to transportation pipelines to ensure it meets pipeline qualityspecifications. The throughput capacity on our Matli treating facility isapproximately 20,000 Mcf/d. During the year ended December 31, 2006, thefacility treated approximately 8,686 Mcf/d of natural gas.

*NaturalGas Supply.**  *Asof December 31, 2006, 48 wells were connected to our Matli gatheringsystem. These wells are located in the Anadarko Basin of central Oklahoma andgenerally have long lives with predictable and steady flow rates. The primarysuppliers of natural gas to the Matli gathering system are CRI and RangeResources Corporation, which represented approximately 59% and 30%,respectively, of the Matli gathering system’s natural gas supply for the yearended December 31, 2006.

The Matli gathering system is located in an activedrilling area. The natural gas supplied to the Matli gathering system isgenerally dedicated to us under individually negotiated long-term contracts.The initial term of such agreements is generally five years with two yearsremaining on most of the contracts. Following the initial term, these contractsgenerally continue on a year-to-year basis, unless terminated by one of theproducers. Natural gas is purchased at the wellhead from the producers underfee-based contracts. For a more complete discussion of our natural gas purchasecontracts, please read “Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Our Contracts—Our Natural Gas PurchaseContracts.”

*Marketsfor Sale of Natural Gas and NGLs.**  *Residue gas resulting from ourprocessing operations is sold at the tailgate of the plant on the Oklahoma GasTransportation intrastate pipeline. As part of our $3.1 million expansion projectmentioned above, we converted an existing natural gas pipeline into a NGLpipeline and now transport NGLs to the ONEOK Hydrocarbon Medford facility.

Our primary purchasers ofresidue gas and NGLs on the Matli gathering system were OGE Energy Resources, ChevronNatural Gas and BP Energy, which represented approximately 41%, 18% and 26%,respectively, of the revenues from such sales for the year ended December 31,2006.

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***Kinta Area Gathering Systems***

*General.**  *The Kinta Area gathering systems,which Hiland Partners acquired from Enogex on May 1, 2006, are located ineastern Oklahoma and consist of five separate natural gas gathering systemswith 573 miles of natural gas gathering pipelines ranging from four inchesto twelve inches in diameter, 26 gas drive compressor units and one electriccompressor unit capable of an aggregate of approximately 40,600 horsepower. Thegathering system has a capacity of approximately 180,000 Mcf/d, and averagethroughput was approximately 134,140 Mcf/d for the eight-month period fromMay 1, 2006 through December 31, 2006. Currently, our operations arelimited to the gathering, dehydration and compression of the natural gassupplied to the Kinta Area gathering systems and the redelivery of thecompressed natural gas for a fixed fee. However, an increasing portion of thenatural gas supplied to the Kinta Area gathering systems has a high carbondioxide content, and consequently, we have begun the installation of fouramine-treating facilities on two of the five systems to remove excess carbondioxide levels from the gas gathered by these gathering systems. We expect thisexpansion will be completed by the end of the first quarter 2007. We alsointend to install additional compression facilities to expand the currentcapacity by approximately 3,000 Mcf/d on these gathering systems. Weexpect this expansion will be completed by the end of the third quarter 2007.

*NaturalGas Supply.**  *Asof December 31, 2006, approximately 689 wells were connected to our KintaArea gathering systems. These wells, which are located in the Arkoma Basin ofeastern Oklahoma, primarily produce natural gas from the Atoka, Cromwell,Booch, Hartshorne, Spiro, Fanshaw and Red Oak formations. The associatednatural gas produced from these wells flows through our Kinta Area gatheringsystems. The primary suppliers of natural gas to this gathering system are BPAmerica Production Company, Chesapeake Energy Marketing, Inc. and ChevronNorth America Exploration and Production Co., which represented approximately49%, 11% and 7%, respectively, of the Kinta Area gathering system’s natural gassupply for the period from May 1, 2006 through December 31, 2006.

The Kinta Area gatheringsystems are located in an active drilling area. Historically, Enogex hasconnected approximately 24 newly drilled wells to these systems on an annualbasis. We believe that this high level of exploration and development activityin the area, including the Woodford shale play to the west of the existingsystem, will continue and that many of the producers drilling in the area willchoose to use our midstream natural gas services due to our excess capacity inthis system and limited competitive alternatives. The natural gas supplied tothe Kinta Area gathering systems is generally dedicated under individuallynegotiated term contracts. The initial term of such agreements is generallythree years.

***Other Systems***

In addition to themidstream assets described above, we own two gathering systems located in Texasand Mississippi and a gathering pipeline system in Oklahoma. These assets donot provide us with material cash flows and consist of the following:

*·**      *Driscoll Gathering System.*  *Our Driscoll gathering system islocated in south Texas and consists of approximately 4 miles of natural gasgathering pipeline and a compressor station.

*·**      *Stovall Gathering System.*  *Our Stovall gathering system islocated in northern Mississippi and consists of approximately 9 miles ofnatural gas gathering pipeline and a compressor station.

*·**      *Enid Pipeline System.*  *Our Enid pipeline system is locatedin northern Oklahoma and consists of approximately 5 miles of pipeline.

**Compression Assets**

We completed construction of our Cedar Hillscompression facility and acquired the Horse Creek compression facility in 2002.The Horse Creek compression facility is comprised of two units with an 

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aggregate of approximately5,300 horsepower. The Cedar Hills compression facility is comprised of tenunits with an aggregate of approximately 40,000 horsepower. The water injectionplant has three pumps with a total of 900 horsepower.

At the compressionfacilities, we compress air to pressures in excess of 4,000 pounds per squareinch. At our water injection plant, water is produced from source wells locatednear the water plant site. Produced water is run through a filter system toremove impurities and is then cooled prior to being pumped to pressures inexcess of 2,000 pounds per square inch. The air and water are delivered at thetailgate of our facilities into pipelines owned by CRI and are ultimatelyutilized by CRI in its oil and gas secondary recovery operations. For adescription of the services agreement we entered into with CRI in connectionwith our initial public offering, please read “Management’s Discussion andAnalysis of Financial Condition and Results of Operations—Our Contracts—CompressionServices Agreement.”

**Competition**

The natural gas gathering, treating, processing andmarketing industries are highly competitive. We face strong competition inacquiring new natural gas supplies. Our competitors include other natural gasgatherers that gather, process and market natural gas. Competition for naturalgas supplies is primarily based on the reputation, efficiency, flexibility andreliability of the gatherer, the pricing arrangements offered by the gathererand the location of the gatherer’s pipeline facilities; a competitive advantagefor us because of our proximity to established and new production. We provideflexible services to natural gas producers, including natural gas gathering,compression, dehydrating, treating and processing. We believe our ability tofurnish these services gives us an advantage in competing for new supplies ofnatural gas because we can provide the services that producers, marketers andothers require to connect their natural gas quickly and efficiently. Inaddition, using centralized treating and processing facilities, we can in mostcases attract producers that require these services more quickly and at a lowerinitial capital cost due in part to the elimination of some field equipment.For natural gas that exceeds the maximum carbon dioxide and NGL specificationsfor interconnecting pipelines and downstream markets, we believe that we offertreating and other processing services on competitive terms. In addition, withrespect to natural gas customers attached to our pipeline systems, we providenatural gas supplies on a flexible basis.

We believe that our producers prefer a midstreamenergy company with the flexibility to accept natural gas not meeting typicalindustry standard gas quality requirements. The primary difference between usand our competitors is that we provide an integrated and responsive package ofmidstream services, while most of our competitors typically offer only a fewselect services. We believe that offering an integrated package of services,while remaining flexible in the types of contractual arrangements that we offerproducers, allows us to compete more effectively for new natural gas supplies.

Many of our competitorshave capital resources and control supplies of natural gas greater than ours.Our primary competitors on the Eagle Chief gathering system are AnadarkoPetroleum Corp., Mustang Fuel Corporation, and Duke Energy Field Services. Ourprimary competitor on the Bakken gathering system and the Badlands gatheringsystem is Bear Paw Energy, and on the Matli gathering system, our competitor isEnogex, Inc. Our primary competitor on the Kinta Area gathering systems isCenterPoint Energy Field Services. We do not have a major competitor on theWorland gathering system.

**Regulation**

*Regulation by the FERC ofInterstate Natural Gas Pipelines.**  *We do not own any interstatenatural gas pipelines, so the Federal Energy Regulatory Commission, or theFERC, does not directly regulate any of our operations. However, the FERC’sregulation influences certain aspects of our business and the market for ourproducts. In general, the FERC has authority over natural gas companies thatprovide natural gas 

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pipelinetransportation services in interstate commerce, and its authority to regulatethose services includes:

·       the certification andconstruction of new facilities;

·       the extension orabandonment of services and facilities;

·       the maintenance of accountsand records;

·       the acquisition anddisposition of facilities;

·       the initiation anddiscontinuation of services; and

·       various other matters.

In recent years, the FERC has pursued pro-competitivepolicies in its regulation of interstate natural gas pipelines. However, wecannot assure you that the FERC will continue this approach as it considersmatters such as pipeline rates and rules and policies that may affectrights of access to natural gas transportation capacity.

*IntrastateRegulation of Natural Gas Transportation Pipelines.**  *We do not own any pipelines thatprovide intrastate natural gas transportation, so state regulation of pipelinetransportation does not directly affect our operations. As with FERC regulationdescribed above, however, state regulation of pipeline transportation mayinfluence certain aspects of our business and the market for our products.

*GatheringPipeline Regulation.**  *Section 1(b) ofthe NGA exempts natural gas gathering facilities from the jurisdiction of theFERC. We own a number of intrastate natural gas pipelines that we believe wouldmeet the traditional tests the FERC has used to establish a pipeline’s statusas a gatherer not subject to the FERC jurisdiction, were it determined thatthose intrastate lines should be classified as interstate lines. However, thedistinction between the FERC-regulated transmission services and federallyunregulated gathering services is the subject of regular litigation, so, insuch a circumstance, the classification and regulation of some of our gatheringfacilities may be subject to change based on future determinations by the FERCand the courts.

In the states in which we operate, regulation ofintrastate gathering facilities generally includes various safety,environmental and, in some circumstances, nondiscriminatory take requirementand complaint based rate regulation. For example, we are subject to stateratable take and common purchaser statutes. Ratable take statutes generallyrequire gatherers to take, without undue discrimination, natural gas productionthat 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 partyservice at a regulated rate. Similarly, common purchaser statutes generallyrequire gatherers to purchase without undue discrimination as to source ofsupply or producer. These statutes are designed to prohibit discrimination infavor of one producer over another producer or one source of supply overanother source of supply. These statutes have the effect of restricting ourright as an owner of gathering facilities to decide with whom we contract topurchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutinyat both the state and federal levels now that the FERC has taken a lessstringent approach to regulation of the gathering activities of interstatepipeline transmission companies and a number of such companies have transferredgathering facilities to unregulated affiliates. Our gathering operations couldbe adversely affected should they be subject in the future to the applicationof state or federal regulation of rates and services. Our gathering operationsalso may be or become subject to safety and operational regulations relating tothe design, installation, testing, construction, operation, replacement andmanagement of gathering facilities. Additional rules and legislationpertaining to these matters are considered or adopted from time to time. Wecannot predict 

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what effect, if any, suchchanges might have on our operations, but the industry could be required toincur additional capital expenditures and increased costs depending on futurelegislative and regulatory changes.

*Sales of Natural Gas.**  *The price at which we buy and sellnatural gas currently is not subject to federal regulation and, for the mostpart, is not subject to state regulation. Our sales of natural gas are affectedby the availability, terms and cost of pipeline transportation. As noted above,the price and terms of access to pipeline transportation are subject toextensive federal and state regulation. The FERC is continually proposing andimplementing new rules and regulations affecting those segments of thenatural gas industry, most notably interstate natural gas transmissioncompanies that remain subject to the FERC’s jurisdiction. These initiativesalso may affect the intrastate transportation of natural gas under certaincircumstances. The stated purpose of many of these regulatory changes is topromote competition among the various sectors of the natural gas industry, andthese initiatives generally reflect more light handed regulation. We cannotpredict the ultimate impact of these regulatory changes to our natural gas marketingoperations, and we note that some of the FERC’s more recent proposals mayadversely affect the availability and reliability of interruptibletransportation service on interstate pipelines. We do not believe that we willbe affected by any such FERC action materially differently than other naturalgas marketers with whom we compete.

**EnvironmentalMatters**

The operation ofpipelines, plants and other facilities for gathering, compressing, dehydrating,treating, or processing of natural gas, NGLs and other products is subject tostringent and complex laws and regulations pertaining to health, safety and theenvironment. As an owner or operator of these facilities, we must comply withthese laws and regulations at the federal, state and local levels. These lawsand regulations can restrict or impact our business activities in many ways,such as:

·       restricting the way we canhandle or dispose of our wastes;

·       limiting or prohibitingconstruction activities in sensitive areas such as wetlands, coastal regions,or areas inhabited by endangered species;

·       requiring remedial actionto mitigate pollution conditions caused by our operations, or attributable toformer operations; and

·       enjoining the operations offacilities deemed in non-compliance with permits issued pursuant to suchenvironmental laws and regulations.

Failure to comply with these laws and regulations maytrigger a variety of administrative, civil and criminal enforcement measures,including the assessment of monetary penalties, the imposition of remedialrequirements, and the issuance of orders enjoining future operations. Certainenvironmental statutes impose strict, joint and several liability for costsrequired to clean up and restore sites where hazardous substances have beendisposed or otherwise released. Moreover, it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury andproperty damage allegedly caused by the release of substances or other wasteproducts into the environment.

The trend in environmental regulation is to place morerestrictions and limitations on activities that may affect the environment, andthus there can be no assurance as to the amount or timing of futureexpenditures for environmental compliance or remediation, and actual futureexpenditures may be different from the amounts we currently anticipate. We tryto anticipate future regulatory requirements that might be imposed and planaccordingly to remain in compliance with changing environmental laws andregulations and to minimize the costs of such compliance. We also activelyparticipate in industry groups that help formulate recommendations foraddressing existing or future regulations.

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We do not believe that compliance with federal, stateor local environmental laws and regulations will have a material adverse effecton our business, financial position or results of operations. In addition, webelieve that the various environmental activities in which we are presentlyengaged are not expected to materially interrupt or diminish our operationalability to gather, compress, treat, fractionate and process natural gas. Wecannot assure you, however, that future events, such as changes in existinglaws, the promulgation of new laws, or the development or discovery of newfacts or conditions will not cause us to incur significant costs. The followingis a discussion of the material environmental and safety laws and regulationsthat can apply to our operations. We believe that we are in substantialcompliance with these environmental laws and regulations.

*AirEmissions.**  *Ouroperations are subject to the federal Clean Air Act and comparable state lawsand regulations. These laws and regulations regulate emissions of airpollutants from various industrial sources, including our processing andtreatment plants, fractionation facilities and compressor stations, and alsoimpose various monitoring and reporting requirements. Such laws and regulationsmay require that we obtain pre-approval for the construction or modification ofcertain projects or facilities expected to produce air emissions or result inthe increase of existing air emissions, obtain and strictly comply with airpermits containing various emissions and operational limitations, or utilizespecific emission control technologies to limit emissions. Our failure to complywith these requirements could subject us to monetary penalties, injunctions,conditions or restrictions on operations, and potentially criminal enforcementactions. We will be required to incur certain capital expenditures in thefuture for air pollution control equipment in connection with obtaining andmaintaining operating permits and approvals for air emissions. We believe,however, that our operations will not be materially adversely affected by suchrequirements, and the requirements are not expected to be any more burdensometo us than to other similarly situated companies.

*HazardousWaste.**  *Ouroperations generate wastes, including some hazardous wastes, that are subjectto the federal Resource Conservation and Recovery Act, or RCRA, and comparablestate laws, which impose detailed requirements for the handling, storage,treatment and disposal of hazardous and solid waste. RCRA currently exemptsmany natural gas gathering and field processing wastes from classification ashazardous waste. Specifically, RCRA excludes from the definition of hazardouswaste produced waters and other wastes associated with the exploration,development, or production of crude oil and natural gas. However, these oil andgas exploration and production wastes may still be regulated under state law orthe less stringent solid waste requirements of RCRA. Moreover, ordinaryindustrial wastes such as paint wastes, waste solvents, laboratory wastes, andwaste compressor oils may be regulated as hazardous waste. The transportationof natural gas in pipelines may also generate some hazardous wastes that aresubject to RCRA or comparable state law requirements.

*SiteRemediation.**  *TheComprehensive Environmental Response, Compensation and Liability Act of 1980,as amended, or CERCLA, also known as “Superfund,” and comparable state lawsimpose liability, without regard to fault or the legality of the originalconduct, on certain classes of persons responsible for the release of hazardoussubstances into the environment. Such classes of persons include the currentand past owners or operators of sites where a hazardous substance was released,and companies that disposed or arranged for disposal of hazardous substances atoffsite locations such as landfills. Although petroleum as well as natural gasis excluded from CERCLA’s definition of “hazardous substance,” in the course ofour ordinary operations we will generate wastes that may fall within thedefinition of a “hazardous substance.” CERCLA authorizes the EPA and, in somecases, third parties to take actions in response to threats to the publichealth or the environment and to seek to recover from the responsible classesof persons the costs they incur. Under CERCLA, we could be subject to joint andseveral liability for the costs of cleaning up and restoring sites wherehazardous substances have been released, for damages to natural resources, andfor the costs of certain health studies.

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*WaterDischarges.**  *Ouroperations are subject to the Federal Water Pollution Control Act of 1972, asamended, also known as the Clean Water Act, and analogous state laws andregulations. These laws and regulations impose detailed requirements and strictcontrols regarding the discharge of pollutants into waters of the UnitedStates. The unpermitted discharge of pollutants, including discharges resultingfrom a spill or leak incident, is prohibited. The Clean Water Act andregulations implemented thereunder also prohibit discharges of dredged and fillmaterial into wetlands and other waters of the United States unless authorizedby an appropriately issued permit. Any unpermitted release of pollutants fromour pipelines or facilities could result in fines or penalties as well assignificant remedial obligations.

*PipelineSafety.**  *Ourpipelines 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, orthe NGPSA, pursuant to which the DOT has established requirements relating tothe design, installation, testing, construction, operation, replacement andmanagement of pipeline facilities. The NGPSA covers the pipeline transportationof natural gas and other gases, and the transportation and storage of liquefiednatural gas and requires any entity that owns or operates pipeline facilitiesto comply with the regulations under the NGPSA, to permit access to and allowcopying of records and to make certain reports and provide information asrequired by the Secretary of Transportation. We believe that our pipelineoperations are in substantial compliance with applicable NGPSA requirements;however, due to the possibility of new or amended laws and regulations orreinterpretation of existing laws and regulations, future compliance with theNGPSA could result in increased costs that, at this time, cannot reasonably bequantified.

The DOT, through the Office of Pipeline Safety,adopted regulations to implement the Pipeline Safety Improvement Act, whichrequires pipeline operators to, among other things, develop integritymanagement programs for gas transmission pipelines that, in the event of afailure, could affect “high consequence areas.” “High consequence areas” aredefined as areas with specified population densities, buildings containingpopulations of limited mobility, and areas where people gather that are locatedalong the route of a pipeline. States in which we operate have adopted similarregulations applicable to intrastate gathering and transmission lines. Ourpipeline systems are largely excluded from these regulations and are notgenerally situated within areas that would be designated “high consequence.”  Therefore, compliance with these regulationshas not had a significant impact on our operations.

*EmployeeHealth and Safety.**  *Weare subject to the requirements of the Occupational Safety and Health Act, orOSHA, and comparable state laws that regulate the protection of the health andsafety of workers. In addition, the OSHA hazard communication standard requiresthat information be maintained about hazardous materials used or produced inour operations and that this information be provided to employees, state andlocal government authorities and citizens.

*Hydrogen Sulfide.**  *Exposure to gas containing highlevels of hydrogen sulfide, referred to as sour gas, is harmful to humans, andexposure can result in death. The gas handled at our Worland gathering systemcontains high levels of hydrogen sulfide, and we employ numerous safetyprecautions at the system to ensure the safety of our employees. There arevarious federal and state environmental and safety requirements for handlingsour gas, and we are in compliance with all such requirements.

**Title to Properties**

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

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Some of our leases, easements, rights-of-way, permits,licenses and franchise ordinances require the consent of the current landownerto transfer these rights, which in some instances is a governmental entity. Webelieve that we have obtained or will obtain sufficient third party consents,permits and authorizations for the transfer of the assets necessary for us tooperate our business in all material respects. With respect to any consents,permits or authorizations that have not been obtained, we believe that theseconsents, permits or authorizations will be obtained reasonably soon, or thatthe failure to obtain these consents, permits or authorizations will have nomaterial adverse effect on the operation of our business.

We lease the majority of the surface land on which ourgathering systems operate. With respect to our Eagle Chief gathering system, welease the surface land on which the Eagle Chief processing plant, three of thefour compressor stations, a produced water dumping station and the three pumpingstations are located. With respect to our Bakken gathering system, we own theland on which the processing plant is located and the land on which thecompressor stations are located. In our Worland gathering system, we lease thesurface land on which the Worland processing plant and the compressor stationsare located. With respect to our Badlands gathering system, we own the land onwhich the Badlands processing plant is located and we lease the land on whichthe four compressor sites are located. We lease the surface lands on which ourMatli processing plant and compressor station are located and we lease thesurface lands on which our Kinta Area compressors are located.

We believe that we have satisfactory title to all ofour assets. Record title to some of our assets may continue to be held by ouraffiliates until we have made the appropriate filings in the jurisdictions inwhich such assets are located and obtained any consents and approvals that arenot obtained prior to transfer. Title to property may be subject toencumbrances. We believe that none of these encumbrances will materiallydetract from the value of our properties or from our interest in theseproperties nor will they materially interfere with their use in the operationof our business.

We believe that we eitherown in fee or have leases, easements, rights-of-way or licenses and haveobtained the necessary consents, permits and franchise ordinances to conductour operations in all material respects.

**Office Facilities**

In addition to ourpipelines and processing facility discussed above, we occupy approximately7,037 square feet of space at our executive offices in Enid, Oklahoma,under a lease expiring on August 31, 2009. While we may require additionaloffice space as our business expands, we believe that our existing facilitiesare adequate to meet our needs for the immediate future and that additionalfacilities will be available on commercially reasonable terms as needed.

**Employees**

We have no employees.Prior to September 25, 2006, employees of our general partner, HilandPartners GP, LLC, provided services to us. In connection with the initialpublic offering of Hiland Holdings, all of the employees of our general partnerbecame employees of the general partner of Hiland Holdings, Hiland Partners GPHoldings, LLC. As of December 31, 2006, Hiland Partners GP Holdings, LLChad 95 full-time employees who provide services to us. We are not a party toany collective bargaining agreements, and we have not had any significant labordisputes in the past. We believe we have good relations with our employees.

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**Address, Internet Web site and Availability of PublicFilings**

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

·       Annual Report on Form 10-K;

·       Quarterly Reports on Form 10-Q;

·       Current Reports on Form 8-K;

·       Amendments to those reports filed or furnishedpursuant to Section 13(a) or 15(d) of the Securities ExchangeAct of 1934;

·       Charters for our Audit, Conflicts, andCompensation Committees;

·       Code of Business Conduct and Ethics; and

·       Code of Ethics for Chief Executive Officer andSenior Financial Officers

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

**Item1A.**                Risk Factors

*Limited partner interests are inherently differentfrom capital stock of a corporation, although many of the business risks towhich we are subject are similar to those that would be faced by a corporationengaged in a similar business. The following risks could materially andadversely affect our business, financial condition or results of operations. Inthat case, the amount of the distributions on our common units could bematerially and adversely affected, the trading price of our common units coulddecline.*

**Risks Related to Our Business**

***Our failure to replace Randy Moeder, our current ChiefExecutive Officer, with an individual with the required level of experience andexpertise in a timely manner, could have an adverse impact on our operationsand business strategy.***

***On March 14, 2007, we announced that Randy Moeder intends toresign as Chief Executive Officer and director of both our general partner andthe general partner of Hiland Holdings GP, LP to pursue other careeropportunities. Mr. Moeder has agreed to remain in such positions forapproximately six months. Mr. Moeder has served as the Chief Executive Officerof our general partner since our inception in October 2004 and has beeninvolved with our predecessor businesses since April 1998. Harold Hamm,Chairman of the board of directors of our general partner, is heading up acommittee to secure a replacement for Mr. Moeder. However, if we areunsuccessful in replacing Mr. Moeder with an individual with the required levelof experience and expertise in a timely manner, our operations and businessstrategy could be materially and adversely affected.***

***We may not have sufficient cash after theestablishment of cash reserves and payment of our general partner’s fees andexpenses to enable us to pay distributions at the current level.***

We may not have sufficientavailable cash each quarter to pay distributions at the current level. Underthe terms of our partnership agreement, we must pay our general partner’s feesand expenses and set aside any cash reserve amounts before making adistribution to our unitholders. The amount of cash we can distribute on ourunits principally depends upon the amount of cash we generate from ouroperations, which will fluctuate from quarter to quarter based on, among otherthings:

·       the amount of natural gasgathered on our pipelines;

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·       the throughput volumes atour processing, treating and fractionation plants;

·       the price of natural gas;

·       the relationship betweennatural gas and NGL prices;

·       the level of our operatingcosts;

·       the weather in ouroperating areas;

·       the level of competitionfrom other midstream energy companies; and

·       the fees we charge and themargins we realize for our services.

In addition, theactual amount of cash we will have available for distribution will depend onother factors, some of which are beyond our control, including:

·       the level of capitalexpenditures we make;

·       the cost of acquisitions,if any;

·       our debt servicerequirements;

·       fluctuations in our workingcapital needs;

·       restrictions ondistributions contained in our credit facility;

·       restrictions on our abilityto make working capital borrowings under our credit facility to paydistributions;

·       prevailing economicconditions; and

·       the amount of cash reservesestablished by our general partner’s board of directors in its sole discretionfor the proper conduct of our business.

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

You should be aware thatthe amount of cash we have available for distribution or to service our debtsecurities depends primarily upon our cash flow, including cash flow fromfinancial reserves and working capital borrowings, and not solely onprofitability, which will be affected by non-cash items. As a result, we mayhave cash available for distributions or debt service during periods when werecord losses and may not have cash available for distributions or debt serviceduring periods when we record net income.

***A significantdecrease in natural gas production in our areas of operation would reduce ourability to make distributions to our unitholders or to service our debtsecurities.***

Our gathering systems are connected to natural gasreserves and wells, from which the production will naturally decline over time,which means that our cash flows associated with these wells will also declineover time. To maintain or increase throughput levels on our gathering systemsand the utilization rate at our processing plants and our treating andfractionation facilities, we must continually obtain new natural gas supplies.Our ability to obtain additional sources of natural gas depends in part on thelevel of successful drilling activity near our gathering systems.

Fluctuations in energyprices can greatly affect production rates and investments by third parties inthe development of new oil and natural gas reserves. Drilling activitygenerally decreases as oil and natural gas prices decrease. Natural gas priceshave been high in recent years compared to historical periods. We have nocontrol over the level of drilling activity in the areas of our operations, theamount of reserves 

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associatedwith the wells or the rate at which production from a well will decline. Inaddition, we have no control over producers or their production decisions,which are affected by, among other things, prevailing and projected energyprices, demand for hydrocarbons, the level of reserves, geologicalconsiderations, governmental regulations and the availability and cost ofcapital. Because we often obtain as new sources of supply associated gas thatis produced in connection with oil drilling operations, declines in oil prices,even without a commensurate decline in prices for natural gas, can adverselyaffect our ability to obtain new gas supplies.

***If we fail toobtain new sources of natural gas supply, our revenues and cash flow may beadversely affected and our ability to make distributions to our unitholders orservice our debt securities reduced.***

We may not be able toobtain additional contracts for natural gas supplies. We face competition inacquiring new natural gas supplies. Competition for natural gas supplies isprimarily based on the location of pipeline facilities, pricing arrangements,reputation, efficiency, flexibility and reliability. Our major competitors fornatural gas supplies and markets include (1) Anadarko Petroleum Corp.,Mustang Fuel Corporation and Duke Energy Field Services LLC at our Eagle Chiefgathering system, (2) Enogex, Inc. at our Matli gathering system, (3) BearPaw Energy, a subsidiary of ONEOK Partners, L.P., at our Badlands and Bakkengathering systems and (4) CenterPoint Energy Field Services at the KintaArea gathering system. Many of our competitors have greater financial resourcesthan we do, which may better enable them to pursue additional gathering andprocessing opportunities than us.

***We depend oncertain 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 naturalgas and adversely affect our financial results.***

For the year ended December 31,2006, CRI, Chesapeake Energy Corporation and Enerplus Resources (USA) Corporationsupplied us with approximately 33%, 24% and 12% respectively, of our totalnatural gas volumes purchased. BP Energy and Chesapeake Energy Corporationsupplied us with approximately 49% and 11% respectively, of our natural gasvolumes gathered. Each of our natural gas gathering systems is dependent on oneor more of these producers. To the extent that these producers reduce thevolumes of natural gas that they supply us as a result of competition orotherwise, we would be adversely affected unless we were able to acquire comparablesupplies of natural gas on comparable terms from other producers, which may notbe possible in areas where the producer that reduces its volumes is the primaryproducer in the area.

***We generally do notobtain independent evaluations of natural gas reserves dedicated to ourgathering systems; therefore, volumes of natural gas gathered on our gatheringsystems in the future could be less than we anticipate.***

We generally do not obtainindependent evaluations of natural gas reserves connected to our gatheringsystems due to the unwillingness of producers to provide reserve information aswell as the cost of such evaluations. Accordingly, we do not have estimates oftotal reserves dedicated to our systems or the anticipated life of suchreserves. If the total reserves or estimated life of the reserves connected toour gathering systems is less than we anticipate and we are unable to secureadditional sources of natural gas, then the volumes of natural gas gathered onour gathering systems in the future could be less than we anticipate. A declinein the volumes of natural gas gathered on our gathering systems would have anadverse effect on our results of operations and financial condition.

***We are exposed tothe credit risks of our key customers, and any material nonpayment ornonperformance by our key customers could reduce our ability to makedistributions to our unitholders or to service our debt securities.***

We are subject to risks ofloss resulting from nonpayment or nonperformance by our customers. Any materialnonpayment or nonperformance by our key customers could reduce our ability tomake distributions to our unitholders. Furthermore, some of our customers maybe highly leveraged and subject 

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to theirown operating and regulatory risks, which increases the risk that they maydefault on their obligations to us.

***Our cash flow isaffected by the volatility of natural gas and NGL product prices, which couldadversely affect our ability to make distributions to unitholders or to serviceour debt securities.***

We are subject to significant risks due to frequentand often substantial fluctuations in commodity prices. In the past, the pricesof natural gas and NGLs have been extremely volatile, and we expect thisvolatility to continue. The markets and prices for natural gas and NGLs dependupon factors beyond our control. These factors include demand for oil, naturalgas and NGLs, which fluctuate with changes in market and economic conditionsand other factors, including:

·       the impact of weather onthe demand for oil and natural gas;

·       the level of domestic oiland natural gas production;

·       the availability ofimported oil and natural gas;

·       actions taken by foreignoil and gas producing nations;

·       the availability of local,intrastate and interstate transportation systems;

·       the availability andmarketing of competitive fuels;

·       the impact of energyconservation efforts; and

·       the extent of governmentalregulation and taxation.

We operate under two typesof contractual arrangements under which our total segment margin is exposed toincreases and decreases in the price of natural gas and NGLs:percentage-of-proceeds and percentage-of-index arrangements. Underpercentage-of-proceeds arrangements, we generally purchase natural gas fromproducers 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 indexrelated prices. Under percentage-of-index arrangements, we purchase natural gasfrom producers at a fixed percentage of the index price for the natural gasthey produce and subsequently sell the residue gas and NGLs or NGL products atmarket prices. Under both of these types of contracts our revenues and totalsegment margin increase or decrease, whichever is applicable, as the price of naturalgas and NGLs fluctuates.

***We may notsuccessfully balance our purchases of natural gas and our sales of residue gasand NGLs, which increases our exposure to commodity price risks.***

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

***Our construction ofnew assets or the expansion of existing assets may not result in revenueincreases and is subject to regulatory, environmental, political, legal andeconomic risks, which could adversely affect our results of operations andfinancial condition.***

One of the ways we maygrow our business is through the construction of new midstream assets or theexpansion of existing systems. The construction of additions or modificationsto our existing systems, and the construction of new midstream assets involvenumerous regulatory, environmental, political and legal uncertainties beyondour control and require the expenditure of significant amounts of capital. Ifwe undertake these projects, they may not be completed on schedule at thebudgeted cost, or at all. Moreover, 

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ourrevenues may not increase immediately upon the expenditure of funds on aparticular project. For instance, if we expand a new pipeline, the constructionmay occur over an extended period of time, and we will not receive any materialincreases in revenues until the project is completed. Moreover, we mayconstruct facilities to capture anticipated future growth in production in aregion in which such growth does not materialize. Since we are not engaged inthe exploration for and development of oil and natural gas reserves, we oftendo not have access to estimates of potential reserves in an area prior toconstructing facilities in such area. To the extent we rely on estimates offuture production in our decision to construct additions to our systems, suchestimates may prove to be inaccurate because there are numerous uncertaintiesinherent in estimating quantities of future production. As a result, newfacilities may not be able to attract enough throughput to achieve our expectedinvestment return, which could adversely affect our results of operations andfinancial condition.

***A change in thecharacterization of some of our assets by federal, state or local regulatoryagencies or a change in policy by those agencies may result in increasedregulation of our assets, which may cause our revenues to decline and operatingexpenses to increase.***

As a natural gas gatherer and intrastate pipelinecompany, we generally are exempt from FERC regulation under the NGA, but FERCregulation still affects our business and the market for our products. FERC’spolicies and practices across the range of its natural gas regulatoryactivities, including, for example, its policies on open access transportation,ratemaking, capacity release, and market center promotion, indirectly affectintrastate markets. In recent years, FERC has pursued pro-competitive policiesin its regulation of interstate natural gas pipelines. However, we cannotassure you that FERC will continue this approach as it considers matters suchas pipeline rates and rules and policies that may affect rights of accessto natural gas transportation capacity. In addition, the distinction betweenFERC-regulated transmission service and federally unregulated gatheringservices is the subject of regular litigation, so, in such a circumstance, theclassification and regulation of some of our gathering facilities may besubject to change based on future determinations by the FERC and the courts.

Other state and localregulations also affect our business. Our gathering lines are subject toratable take and common purchaser statutes in states in which we operate. Ratabletake statutes generally require gatherers to take, without unduediscrimination, natural gas production that may be tendered to the gatherer forhandling. Similarly, common purchaser statutes generally require gatherers topurchase without undue discrimination as to source of supply or producer. Thesestatutes restrict our right as an owner of gathering facilities to decide withwhom we contract to purchase or transport natural gas. Federal law leaves anyeconomic regulation of natural gas gathering to the states. States in which weoperate have adopted complaint based regulation of natural gas gatheringactivities, which allows natural gas producers and shippers to file complaintswith state regulators in an effort to resolve grievances relating to naturalgas gathering access and rate discrimination. While our proprietary gatheringlines currently are subject to limited state regulation, there is a risk thatstate laws will be changed, which may give producers a stronger basis tochallenge proprietary status of a line, or the rates, terms and conditions of agathering line providing transportation service.

***We may incursignificant costs and liabilities in the future resulting from a failure tocomply with new or existing environmental regulations or an accidental releaseof hazardous substances into the environment.***

Our operations are subject to stringent and complexfederal, state and local environmental laws and regulations. These include, forexample, (i) the federal Clean Air Act and comparable state laws andregulations that impose obligations related to air emissions, (ii) RCRAand comparable state laws that impose requirements for the discharge of wastefrom our facilities and (iii) CERCLA, also known as “Superfund,” andcomparable state laws that regulate the cleanup of hazardous substances thatmay have been released at properties currently or previously owned or operatedby us or locations to which we have 

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sent waste for disposal.Failure to comply with these laws and regulations or newly adopted laws orregulations may trigger a variety of administrative, civil and criminalenforcement measures, including the assessment of monetary penalties, theimposition of remedial requirements, and the issuance of orders enjoiningfuture operations. Certain environmental statutes, including CERCLA andanalogous state laws and regulations, impose strict, joint and severalliability for costs required to clean up and restore sites where hazardoussubstances have been disposed or otherwise released. Moreover, it is notuncommon for neighboring landowners and other third parties to file claims forpersonal injury and property damage allegedly caused by the release ofhazardous substances or other waste products into the environment.

There is inherent risk ofthe incurrence of environmental costs and liabilities in our business due toour handling of natural gas and other petroleum products, air emissions relatedto our operations, and historical industry operations and waste disposalpractices. For example, an accidental release from one of our pipelines orprocessing facilities could subject us to substantial liabilities arising fromenvironmental cleanup and restoration costs, claims made by neighboringlandowners and other third parties for personal injury and property damage, andfines or penalties for related violations of environmental laws or regulations.Moreover, the possibility exists that stricter laws, regulations or enforcementpolicies could significantly increase our compliance costs and the cost of anyremediation that may become necessary. We may not be able to recover thesecosts from insurance.

***If we do not make acquisitions on economicallyacceptable terms, our future growth will be limited.***

Our ability to grow depends on our ability to makeacquisitions that result in an increase in the cash generated from operationsper unit. If we are unable to make these accretive acquisitions because we are:(1) unable to identify attractive acquisition candidates or negotiateacceptable purchase contracts with them, (2) unable to obtain financing for theseacquisitions on economically acceptable terms, or (3) outbid bycompetitors, then our future growth and ability to increase distributions willbe limited. Furthermore, even if we do make acquisitions that we believe willbe accretive, these acquisitions may nevertheless result in a decrease in thecash generated from operations per unit.

Any acquisition, including our recent acquisition ofthe Kinta Area gathering assets, involves potential risks, including, amongother things:

·       mistaken assumptions aboutrevenues and costs, including synergies;

·       an inability to integratesuccessfully the businesses we acquire;

·       the assumption of unknownliabilities;

·       limitations on rights toindemnity from the seller;

·       the diversion of management’sattention from other business concerns;

·       unforeseen difficultiesoperating in new product areas or new geographic areas; and

·       customer or key employeelosses at the acquired businesses.

If we consummate any future acquisitions, ourcapitalization and results of operations may change significantly, and you willnot have the opportunity to evaluate the economic, financial and other relevantinformation that we will consider in determining the application of these fundsand other resources.

Our acquisition approachis based, in part, on our expectation of ongoing divestitures of midstreamassets by large industry participants. A material decrease in such divestitureswould limit our opportunities for future acquisitions and could adverselyaffect our operations and cash flows available for distribution to ourunitholders.

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***Our ability toengage in construction projects and to make acquisitions will require access toa substantial amount of capital.***

Our ability to engage inconstruction projects or to make acquisitions is dependent on obtainingadequate sources of outside financing, including commercial borrowings andother debt and common unit issuances. While the initial funding of ouracquisitions may consist of debt financing, our financial strategy is tofinance acquisitions approximately equally with equity and debt, and we wouldexpect to repay such debt with proceeds of equity issuances to achieve thisrelatively balanced financing ratio. If we are unable to finance our growth throughexternal sources or are unable to achieve our targeted debt/equity ratios, orif the cost of such financing is higher than expected, we may be required toforgo certain construction projects or acquisition opportunities or suchconstruction projects or acquisition opportunities may not result in expectedincreases in distributable cash flow. Accordingly, our inability to obtainadequate sources of financing on economically acceptable terms may limit ourgrowth opportunities, which could have a negative impact on our cash availableto pay distributions.

***Cost reimbursementsdue to our general partner may be substantial and will reduce cash availablefor distribution to holders of our common units or to service our debtsecurities.***

Prior to making any distributionon our common units, we will reimburse our general partner for expenses itincurs on our behalf. The reimbursement of expenses could adversely affect ourability to pay cash distributions to holders of our common units. Our generalpartner will determine the amount of these expenses. In addition, our generalpartner and its affiliates may perform other services for us for which we willbe charged fees as determined by our general partner.

***If we are unable toobtain new rights-of-way or the cost of renewing existing rights-of-wayincreases, then we may be unable to fully execute our growth strategy and ourcash flows could be adversely affected.***

The construction ofadditions to our existing gathering assets may require us to obtain newrights-of-way prior to constructing new pipelines. We may be unable to obtainsuch rights-of-way to connect new natural gas supplies to our existinggathering lines or capitalize on other attractive expansion opportunities.Additionally, it may become more expensive for us to obtain new rights-of-wayor to renew existing rights-of-way. If the cost of obtaining new rights-of-wayor renewing existing rights-of-way increases, then our cash flows could beadversely affected.

***Our businessinvolves many hazards and operational risks, some of which may not be fullycovered by insurance. If a significant accident or event occurs that is notfully insured, our operations and financial results could be adverselyaffected.***

Our operations aresubject to the many hazards inherent in the gathering, treating, processing andfractionation of natural gas and NGLs, including:

·       damage to pipelines,related equipment and surrounding properties caused by tornadoes, floods, firesand other natural disasters and acts of terrorism;

·       inadvertent damage fromconstruction and farm equipment;

·       leaks of natural gas, NGLsand other hydrocarbons or losses of natural gas or NGLs as a result of themalfunction of measurement equipment or facilities at receipt or deliverypoints;

·       fires and explosions; and

·       other hazards, includingthose associated with high-sulfur content, or sour gas, that could also resultin personal injury and loss of life, pollution and suspension of operations.

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These risks could resultin substantial losses due to personal injury and/or loss of life, severe damageto and destruction of property and equipment and pollution or otherenvironmental damage and may result in curtailment or suspension of our relatedoperations. A natural disaster or other hazard affecting the areas in which weoperate could have a material adverse effect on our operations. We are notfully insured against all risks incident to our business. In accordance withtypical industry practice, we do not have any property insurance on any of ourunderground pipeline systems that would cover damage to the pipelines. We arenot insured against all environmental accidents that might occur, other thanthose considered to be sudden and accidental. In addition, we do not havebusiness interruption insurance. If a significant accident or event occurs thatis not fully insured, it could adversely affect our operations and financialcondition.

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

Our credit facilitycontains various covenants limiting our ability to incur indebtedness, grantliens, engage in transactions with affiliates, make distributions to ourunitholders and capitalize on acquisition or other business opportunities. Italso contains covenants requiring us to maintain certain financial ratios andtests. We are prohibited from making any distribution to unitholders if suchdistribution would cause a default or an event of default under our creditfacility. Any subsequent refinancing of our current indebtedness or any newindebtedness could have similar or greater restrictions. At December 31,2006, our total outstanding long-term indebtedness was approximately $147.1million, all under our senior secured revolving credit facility. Payments ofprincipal and interest on the indebtedness will reduce the cash available fordistribution on our units.

***Due to our lack ofasset diversification, adverse developments in our midstream operations would reduceour ability to make distributions to our unitholders or to service our debtsecurities.***

We rely exclusively on therevenues generated from our gathering, dehydration, treating, processing,fractionation and compression services businesses, and as a result, ourfinancial condition depends upon prices of, and continued demand for, naturalgas and NGLs. Due to our lack of diversification in asset type, an adversedevelopment in one of these businesses would have a significantly greaterimpact on our financial condition and results of operations than if wemaintained more diverse assets.

***Increases ininterest rates, which have recently experienced record lows, could adverselyimpact our unit price and our ability to issue additional equity to makeacquisitions, reduce debt or finance internal growth projects.***

If the overall economystrengthens, it is likely that monetary policy will tighten further, resultingin higher interest rates to counter possible inflation. Interest rates onfuture credit facilities and debt offerings could be higher than currentlevels, causing our financing costs to increase accordingly. As with otheryield-oriented securities, our unit price is impacted by the level of our cashdistributions and implied distribution yield. The distribution yield is oftenused by investors to compare and rank related yield-oriented securities forinvestment decision making purposes. Therefore, changes in interest rates,either positive or negative, may affect the yield requirements of investors whoinvest in our units, and a rising interest rate environment could have anadverse impact on our unit price and our ability to issue additional equity tomake acquisitions, reduce debt or finance internal growth projects.

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

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

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prices. While our hedgingactivities are designed to reduce commodity price risk, we remain exposed tofluctuations in commodity prices to some extent.

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

As a result of thesefactors, our hedging activities may not be as effective as we intend inreducing the volatility of our cash flows, and in certain circumstances mayactually increase the volatility of our cash flows. In addition, our hedgingactivities are subject to the risks that a counterparty may not perform itsobligation under the applicable derivative instrument, the terms of thederivative instruments are imperfect, and our hedging procedures may not beproperly followed. We cannot assure you that the steps we take to monitor ourderivative financial instruments will detect and prevent violations of our riskmanagement policies and procedures, particularly if deception or otherintentional misconduct is involved.

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

The long-term impact of terrorist attacks, such as theattacks that occurred on September 11, 2001, and the threat of futureterrorist attacks, on the energy transportation industry in general, and on usin particular, is not known at this time. Increased security measures taken byus as a precaution against possible terrorist attacks have resulted inincreased costs to our business. Uncertainty surrounding continued hostilitiesin the Middle East or other sustained military campaigns may affect ouroperations in unpredictable ways, including disruptions of crude oil suppliesand markets for refined products, and the possibility that infrastructurefacilities could be direct targets of, or indirect casualties of, an act ofterror.

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

**Risks Inherent inan Investment in Us**

***Harold Hamm and hisaffiliates control our general partner, which has sole responsibility forconducting our business and managing our operations. Affiliates of Harold Hammand our general partner have conflicts of interest and limited fiduciaryduties, which may permit them to favor their own interests to your detriment.***

Harold Hamm and hisaffiliates control Hiland Partners GP Holdings, LLC, the general partner ofHiland Holdings, a publicly traded Delaware limited partnership that directlyor indirectly owns 100% of our general partner. As a result, Harold Hamm andhis affiliates control our general partner, which has sole responsibility forconducting our business and managing our operations. Conflicts of interest mayarise between Harold Hamm and his affiliates, including our general partner, onthe one hand, and us and our unitholders, on the other hand. As a result ofthese conflicts, the general partner may favor its own 

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

·       Harold Hamm controls CRI;neither our partnership agreement nor any other agreement requires CRI topursue a business strategy that favors us;

·       our general partner isallowed to take into account the interests of parties other than us, inresolving conflicts of interest;

·       our general partner haslimited its liability and reduced its fiduciary duties, and has also restrictedthe remedies available to our unitholders for actions that, without thelimitations, might constitute breaches of fiduciary duty;

·       our general partnerdetermines the amount and timing of asset purchases and sales, capitalexpenditures, borrowings, issuance of additional limited partner securities,and reserves, each of which can affect the amount of cash that is distributedto unitholders;

·       our partnership agreementdoes not restrict our general partner from causing us to pay it or itsaffiliates for any services rendered to us or entering into additionalcontractual arrangements with any of these entities on our behalf;

·       our general partnercontrols the enforcement of obligations owed to us by our general partner andits affiliates; and

·       our general partner decideswhether to retain separate counsel, accountants, or others to perform servicesfor us.

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

Unitholders have only limited voting rights on mattersaffecting our operations and activities and, therefore, limited ability toinfluence management’s decisions regarding our business. Unitholders did notselect our general partner or elect the board of directors of our generalpartner and effectively have no right to select our general partner or electits board of directors in the future.

Unitholders’ voting rightsare further restricted by the partnership agreement provision providing thatany units held by a person that owns 20% or more of any class of units thenoutstanding, other than the general partner, its affiliates, their transfereesand persons who acquired such units with the prior approval of the board ofdirectors of our general partner, cannot be voted on any matter. In addition,the partnership agreement contains provisions limiting the ability ofunitholders to call meetings or to acquire information about our operations, aswell as other provisions limiting the unitholders’ ability to influence themanner or direction of management.

***Our general partnerdetermines the cost reimbursement and fees payable to it from us; such paymentsmay be substantial and could reduce our cash available for distribution to you.***

Payments to our general partner may be substantial andwill reduce the amount of available cash for distribution to unitholders. Wewill reimburse our general partner for the provision by it and its affiliatesof various general and administrative services for our benefit, including thesalaries and costs of employee benefits for employees of the general partnerand its affiliates that provide services to us. Our general partner determinesthe amount of expenses allocable to us. There is no cap on the amount that maybe paid or reimbursed to our general partner for compensation or expensesincurred on our behalf. Our general partner and its affiliates also may provideus other services for which we will be charged fees as determined by ourgeneral partner.

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***Our partnershipagreement limits our general partner’s fiduciary duties to our unitholders andrestricts the remedies available to unitholders for actions taken by ourgeneral partner that might otherwise constitute breaches of fiduciary duty.***

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

·       permits our general partnerto make a number of decisions in its individual capacity, as opposed to in itscapacity as our general partner. This entitles our general partner to consideronly the interests and factors that it desires, and it has no duty orobligation to give any consideration to any interest of, or factors affecting,us, our affiliates or any limited partner;

·       provides that our generalpartner is entitled to make other decisions in “good faith” if it reasonablybelieves that the decision is in our best interests;

·       generally provides thataffiliated transactions and resolutions of conflicts of interest not approvedby the conflicts committee of the board of directors of our general partner andnot involving a vote of unitholders must be on terms no less favorable to usthan those generally being provided to or available from unrelated thirdparties or be “fair and reasonable” to us and that, in determining whether atransaction or resolution is “fair and reasonable,” our general partner mayconsider the totality of the relationships between the parties involved, includingother transactions that may be particularly advantageous or beneficial to us;and

·       provides that our generalpartner and its officers and directors will not be liable for monetary damagesto us, our limited partners or assignees for any acts or omissions unless therehas been a final and non-appealable judgment entered by a court of competentjurisdiction determining that the general partner or those other persons actedin bad faith or engaged in fraud or willful misconduct or, in the case of a criminalmatter, acted with knowledge that such person’s conduct was criminal.

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

***Harold Hamm and CRI may engage in limited competitionwith us.***

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

·       any business that isprimarily related to the exploration for and production of oil or natural gas,including the sale and marketing of oil and natural gas derived from suchexploration and production activities;

·       any business conducted byHarold Hamm or his affiliates as of the date of the omnibus agreement;

·       the purchase and ownershipof not more than five percent of any class of securities of any entity engagedin any restricted business (but without otherwise participating in theactivities of such entity);

·       any business that HaroldHamm or his affiliates acquires or constructs that has a fair market value orconstruction cost, as applicable, of less than $5.0 million;

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·       any business that HaroldHamm or his affiliates acquires or constructs that has a fair market value orconstruction cost, as applicable, of $5.0 million or more if we have beenoffered the opportunity to purchase the business for the fair market value orconstruction cost, as applicable, and we decline to do so with the concurrenceof the conflicts committee of our general partner; and

·       any business conducted byHarold Hamm or his affiliates with the approval of the conflicts committee.

Thesenon-competition obligations will terminate on the first to occur of thefollowing events:

·       the first day on whichHarold Hamm and his affiliates no longer control us;

·       the death of Harold Hamm;and

·       February 15, 2010, thefifth anniversary of the closing of our initial public offering.

In addition, in connectionwith the initial public offering of Hiland Holdings, Hiland Holdings and itsgeneral partner entered into a non-competition agreement with us pursuant towhich 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 itsgeneral partner (other than our general partner, our subsidiaries and us) notto, engage in, whether by acquisition, construction, investment in debt orequity interests of any person or otherwise, the business of gathering,treating, processing and transportation of natural gas in North America, thetransportation and fractionation of NGLs in North America, and constructing,buying or selling any assets related to the foregoing businesses. Thenon-competition agreement has the same permitted exceptions as the omnibusagreement and will terminate on the first day on which neither Hiland Holdingsnor its general partner control us.

***Even if unitholders are dissatisfied, they cannotremove 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 businessand, therefore, limited ability to influence management’s decisions regardingour business. Unitholders did not elect our general partner or the board ofdirectors of our general partner and will have no right to elect our generalpartner or the board of directors of our general partner on an annual or othercontinuing basis. The board of directors of our general partner is chosen bythe members of our general partner. Furthermore, if the unitholders weredissatisfied with the performance of our general partner, they would havelittle 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 ofthe absence or reduction of a takeover premium in the trading price.

The unitholders are unable initially to remove thegeneral partner without its consent because the general partner and itsaffiliates own sufficient units to be able to prevent removal. The vote of theholders of at least 662¤3% of all outstanding units votingtogether as a single class is required to remove the general partner. As of March 5,2007, affiliates of the general partner owned 57.8% of the units outstanding.Also, if the general partner is removed without cause during the subordinationperiod and units held by the general partner and its affiliates are not votedin favor of that removal, all remaining subordinated units will automaticallyconvert into common units and any existing arrearages on the common units willbe extinguished. A removal of the general partner under these circumstanceswould adversely affect the common units by prematurely eliminating theirdistribution and liquidation preference over the subordinated units, whichwould otherwise have continued until we had met certain distribution andperformance tests. Cause is narrowly defined to mean that a court of competentjurisdiction has entered a final, non-appealable judgment finding the generalpartner liable for actual fraud, gross negligence, or willful or wantonmisconduct in its capacity as our general partner. Cause does not include mostcases of charges of poor management of the business, so the removal of thegeneral partner because of the 

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unitholder’sdissatisfaction with the general partner’s performance in managing ourpartnership would most likely result in the termination of the subordinationperiod.

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

***The control of our general partner may be transferredto a third party without unitholder consent.***

Our general partner maytransfer its general partner interest to a third party in a merger or in a saleof all or substantially all of its assets without the consent of theunitholders. Furthermore, our partnership agreement does not restrict theability of the members of our general partner from transferring theirrespective membership interests in our general partner to a third party. Thenew members of our general partner would then be in a position to replace theboard of directors of our general partner with their own choices and to controlthe decisions taken by the board of directors.

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

We do not have our ownofficers and employees and rely solely on the officers and employees of ourgeneral partner and its affiliates to manage our business and affairs. We canprovide no assurance that the general partner will continue to provide us theofficers and employees that are necessary for the conduct of our business northat such provision will be on terms that are acceptable to us. Other thanoption agreements, neither we nor our general partner have entered into anyemployment agreements with any officers of our general partner. If the general partnerfails to provide us with adequate personnel, our operations could be adverselyimpacted. In addition, certain of the officers of our general partner,including the chief executive officer and chief financial officer, may alsoserve as officers and directors of affiliates of the general partner.

***We may issueadditional common units without your approval, which would dilute your existingownership interests.***

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

·       the issuance of commonunits upon the exercise of the underwriters’ over-allotment option;

·       the issuance of commonunits in connection with acquisitions or capital improvements that increasecash flow from operations per unit on an estimated pro forma basis;

·       issuances of common unitsto repay indebtedness, if the cost to service the indebtedness is greater thanthe distribution obligations associated with the units issued in connectionwith the repayment of the indebtedness;

·       the conversion ofsubordinated units into common units;

·       the conversion of units ofequal rank with the common units into common units under some circumstances;

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·       in the event of acombination or subdivision of common units;

·       issuances of common unitsunder our employee benefit plans; or

·       the conversion of thegeneral partner interest and the incentive distribution rights into commonunits as a result of the withdrawal or removal of our general partner.

In addition, our partnership agreement does notprohibit the issuance by our subsidiaries of equity securities, which mayeffectively rank senior to the common units.

The issuance ofadditional common units or other equity securities of equal or senior rank willhave the following effects:

·       our unitholders’proportionate ownership interest in us may decrease;

·       the amount of cashavailable for distribution on each unit may decrease;

·       because a lower percentageof total outstanding units will be subordinated units, the risk that ashortfall in the payment of the minimum quarterly distribution will be borne byour common unitholders will increase;

·       the relative votingstrength of each previously outstanding unit may be diminished;

·       the market price of thecommon units may decline; and

·       the ratio of taxable incometo distributions may increase.

After the end of thesubordination period, we may issue an unlimited number of limited partnerinterests of any type without the approval of our unitholders. Our partnershipagreement does not give our unitholders the right to approve our issuance ofequity securities ranking junior to the common units at any time.

***Our general partner’sdiscretion in determining the level of cash reserves may reduce the amount ofavailable cash for distribution to you.***

Our partnership agreementrequires our general partner to deduct from operating surplus cash reservesthat it determines are necessary to fund our future operating expenditures. Inaddition, our partnership agreement also permits our general partner to reduceavailable cash by establishing cash reserves for the proper conduct of ourbusiness, to comply with applicable law or agreements to which we are a party,or to provide funds for future distributions to partners. These reserves willaffect the amount of cash available for distribution to you.

***Our general partnermay cause us to borrow funds in order to make cash distributions, even wherethe purpose or effect of the borrowing benefits our general partner or itsaffiliates.***

In some instances, ourgeneral partner may cause us to borrow funds in order to permit the payment ofcash distributions. These borrowings are permitted even if the purpose andeffect of the borrowing is to enable us to make a distribution on thesubordinated units, to make incentive distributions, or to hasten theexpiration of the subordination period.

***All of themembership interests in our general partner and all of the common andsubordinated units in us that are owned by Hiland Holdings are pledged assecurity under Hiland Holdings’ credit facility. Upon an event of default underHiland Holdings’ credit facility, a change in ownership or control of us couldultimately result.***

The 100% membershipinterest in our general partner and the 1,301,471 common units and 4,080,000subordinated units in us that are owned by Hiland Holdings are pledged underHiland Holdings’ credit facility. Hiland Holdings’ credit facility containscustomary and other events of default. Upon an event of 

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default,the lenders under Hiland Holdings’ credit facility could foreclose on HilandHoldings’ assets, which could ultimately result in a change in control of ourgeneral partner and a change in the ownership of our units held by HilandHoldings.

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

If at any time our generalpartner and its affiliates own more than 80% of the common units, our generalpartner will have the right, but not the obligation, which it may assign to anyof its affiliates or to us, to acquire all, but not less than all, of thecommon units held by unaffiliated persons at a price not less than theirthen-current market price. As a result, you may be required to sell your commonunits at an undesirable time or price and may not receive any return on yourinvestment. You may also incur a tax liability upon a sale of your units. As ofMarch 5, 2007, affiliates of our general partner owned approximately 24.9%of the common units and, at the end of the subordination period, assuming noadditional issuances of common units, affiliates of our general partner willown approximately 57.8% of the common units.

***You could be liablefor any and all of our obligations if a court finds that unitholder actionconstitutes control of our business.***

A general partnerof a partnership generally has unlimited liability for the obligations of thepartnership, except for those contractual obligations of the partnership thatare expressly made without recourse to the general partner. Our partnership isorganized under Delaware law and we conduct business in a number of otherstates. The limitations on the liability of holders of limited partnerinterests for the obligations of a limited partnership have not been clearlyestablished in some of the other states in which we do business. You could beliable for any and all of our obligations as if you were a general partner if:

·       a court or governmentagency determined that we were conducting business in a state but had notcomplied with that particular state’s partnership statute; or

·       your right to act withother unitholders to remove or replace the general partner, to approve someamendments to our partnership agreement or to take other actions under ourpartnership agreement constitute “control” of our business.

***Unitholders may have liability to repay distributionsthat were wrongfully distributed to them.***

Under certaincircumstances, unitholders may have to repay amounts wrongfully returned ordistributed to them. Under Section 17-607 of the Delaware RevisedUniform Limited Partnership Act, we may not make a distribution to you if thedistribution would cause our liabilities to exceed the fair value of ourassets. Delaware law provides that for a period of three years from the date ofthe impermissible distribution, limited partners who received the distributionand who knew at the time of the distribution that it violated Delaware law willbe liable to the limited partnership for the distribution amount. Substitutedlimited partners are liable for the obligations of the assignor to makecontributions to the partnership that are known to the substituted limitedpartner at the time it became a limited partner and for unknown obligations ifthe liabilities could be determined from the partnership agreement. Liabilitiesto partners on account of their partnership interest and liabilities that arenon-recourse to the partnership are not counted for purposes of determiningwhether a distribution is permitted.

38

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**Tax Risks to CommonUnitholders**

***Our tax treatmentdepends on our status as a partnership for federal income tax purposes, as wellas our not being subject to a material amount of entity-level taxation byindividual states. If the IRS were to treat us as a corporation or if we becomesubject to a material amount of entity-level taxation for state tax purposes,it would reduce the amount of cash available for distribution to you.***

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

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

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

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

***If the IRS conteststhe federal income tax positions we take, the market for our common units maybe adversely impacted and the cost of any IRS contest will reduce our cashavailable for distribution to you.***

We have not requested aruling from the IRS with respect to our treatment as a partnership for federalincome tax purposes or any other matter affecting us. The IRS may adoptpositions that differ from the conclusions of our counsel expressed in thisprospectus or from the positions we take. It may be necessary to resort toadministrative or court proceedings to sustain some or all of our counsel’sconclusions or the positions we take. A court may not agree with some or all ofour counsel’s conclusions or positions we take. Any contest with the IRS maymaterially and adversely impact the market for our common units and the priceat which they trade. In addition, our costs of any contest with the IRS will beborne indirectly by our unitholders and our general partner because the costswill reduce our cash available for distribution.

***You may be requiredto pay taxes on your share of our income even if you do not receive any cashdistributions from us.***

Because our unitholderswill be treated as partners to whom we will allocate taxable income which couldbe different in amount than the cash we distribute, you will be required to payany federal income taxes and, in some cases, state and local income taxes onyour share of our taxable income even if you 

39

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receiveno cash distributions from us. You may not receive cash distributions from usequal to your share of our taxable income or even equal to the actual taxliability that results from that income.

***Tax gain or loss on disposition of our common unitscould be more or less than expected.***

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

***Tax-exempt entitiesand foreign persons face unique tax issues from owning our common units thatmay result in adverse tax consequences to them.***

Investment in common unitsby tax-exempt entities, such as individual retirement accounts (known as IRAs),and non-U.S. persons raises issues unique to them. For example, virtually allof our income allocated to organizations that are exempt from federal incometax, including individual retirement accounts and other retirement plans, willbe unrelated business taxable income and will be taxable to them. Distributionsto non-U.S. persons will be reduced by withholding taxes at the highestapplicable effective tax rate, and non-U.S. persons will be required to fileUnited States federal tax returns and pay tax on their share of our taxableincome. If you are a tax exempt entity or a foreign person, you should consultyour tax advisor before investing in our common units.

***We will treat eachpurchaser of common units as having the same tax benefits without regard to theactual common units purchased. The IRS may challenge this treatment, whichcould adversely affect the value of the common units.***

Because we cannot matchtransferors and transferees of common units and because of other reasons, wewill adopt depreciation and amortization positions that may not conform to allaspects of existing Treasury Regulations. A successful IRS challenge to thosepositions 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 gainfrom your sale of common units and could have a negative impact on the value ofour common units or result in audit adjustments to your tax returns.

***The sale orexchange of 50% or more of our capital and profits interests during anytwelve-month period will result in the termination of our partnership forfederal income tax purposes.***

We will be considered tohave terminated for federal income tax purposes if there is a sale or exchangeof 50% or more of the total interests in our capital and profits within atwelve-month period. Our termination would, among other things, result in theclosing of our taxable year for all unitholders and could result in a deferralof depreciation deductions allowable in computing our taxable income.

***You will likely besubject to state and local taxes and return filing requirements in states whereyou do not live as a result of investing in our common units.***

In addition to federalincome taxes, you will likely be subject to other taxes, including foreign,state and local taxes, unincorporated business taxes and estate, inheritance orintangible taxes that are imposed 

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by thevarious jurisdictions in which we do business or own property, even if you donot live in any of those jurisdictions. You will likely be required to fileforeign, state and local income tax returns and pay state and local incometaxes in some or all of these various jurisdictions. Further, you may besubject to penalties for failure to comply with those requirements. Wecurrently do business or own property in Mississippi, Montana, North Dakota,Oklahoma, Texas and Wyoming. Each of these states, except Texas and Wyomingcurrently impose a personal income tax. As we make acquisitions or expand ourbusiness, we may own assets or conduct business in additional states thatimpose a personal income tax. It is your responsibility to file all UnitedStates federal, foreign, state and local tax returns. Our counsel has notrendered an opinion on the state or local tax consequences of an investment inour common units.

**Item 1B.**               UnresolvedStaff Comments

None.

**Item 3.**                        LegalProceedings

Although we may, from timeto time, be involved in litigation and claims arising out of our operations inthe normal course of business, we are not currently a party to any material legalproceedings. In addition, we are not aware of any legal or governmentalproceedings against us, or contemplated to be brought against us, under thevarious environmental protection statutes to which we are subject. We maintaininsurance policies with insurers in amounts and with coverage and deductiblesas our general partner believes are reasonable and prudent. However, we cannotassure you that this insurance will be adequate to protect us from all materialexpenses related to potential future claims for personal and property damage orthat these levels of insurance will be available in the future at economicalprices.

**Item 4.**                        Submissionof Matters to a Vote of Security Holders

None.

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**PART II**

**Item 5.**                        Market forRegistrant’s Common Units and Related Unitholder Matters and Issuer Purchasesof Equity Securities

Our limited partner common units began trading on theNasdaq National Market under the symbol “HLND” commencing with our initial publicoffering on February 10, 2005 at an initial public offering price of$22.50 per common unit. As of March 5, 2007, the market price for thecommon units was $53.02 per unit and there were approximately 3,900 commonunitholders, including beneficial owners of common units held in street nameand one record holder of our subordinated units. There is no established publictrading market for our subordinated units. We intend to consider cashdistributions to unitholders on a quarterly basis, although there is noassurance as to the future cash distributions since they are dependent uponfuture earnings, cash flows, capital requirements, financial condition andother factors. Our ability to distribute available cash is contractuallyrestricted by the terms of our credit facility. Our credit facility containscovenants requiring us to maintain certain financial ratios. We are prohibitedfrom making any distributions to unitholders if the distribution would cause anevent of default, or an event of default exists, under our credit facility.Please read “Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Liquidity and Capital Resources—Descriptionof Indebtedness—Credit Facility.”

Thefollowing table shows the high and low prices per common unit, as reported bythe NASDAQ National Market, for the periods indicated. Cash distributions shownwere paid within 45 days after the end of each quarter.

| ** **                               | ** ** | **Common Unit  Price Ranges** | ** ** | **Cash Distribution** | ** ** |
|------------------------------------------|------------|-----------------------------------------|------------|----------------------------|------------|
| ** **                               | ** ** | **High**                                | ** ** | **Low**                    | ** ** | **Paid Per Unit(a)** | ** ** |
| ***Year  Ended December 31, 2006*** |       |                                    |       |                       |       |   |   |   |   |
| Quarter Ended  December 31          |       | $                                       | 56.86      |                       | $          | 44.00 |   |   | $ | 0.7125 |   |   |
| Quarter Ended  September 30         |       | $                                       | 47.33      |                       | $          | 42.00 |   |   | $ | 0.7000 |   |   |
| Quarter Ended  June 30              |       | $                                       | 46.58      |                       | $          | 41.21 |   |   | $ | 0.6750 |   |   |
| Quarter Ended  March 31             |       | $                                       | 43.95      |                       | $          | 36.84 |   |   | $ | 0.6500 |   |   |
| ***Year  Ended December 31, 2005*** |       |                                    |       |                       |       |   |   |   |   |
| Quarter Ended  December 31          |       | $                                       | 46.47      |                       | $          | 34.50 |   |   | $ | 0.6250 |   |   |
| Quarter Ended  September 30         |       | $                                       | 46.22      |                       | $          | 34.58 |   |   | $ | 0.5125 |   |   |
| Quarter Ended  June 30              |       | $                                       | 37.32      |                       | $          | 31.17 |   |   | $ | 0.4625 |   |   |
| Quarter Ended  March 31             |       | $                                       | 35.00      |                       | $          | 27.50 |   |   | $ | 0.2250 | (b) |   |

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(a)           For each quarter, anidentical per unit cash distribution was paid on all outstanding subordinatedunits.

(b)          Reflectsthe pro rata portion of the $0.45 minimum quarterly distribution per unit,representing the period from the February closing of our initial publicoffering through March 31, 2005.

*Cash DistributionPolicy*

Within 45 days after the end of each quarter, we willdistribute all of our available cash (as defined in our partnership agreement)to unitholders of record on the applicable record date. The amount of availablecash generally is all cash on hand at the end of the quarter less the amount ofcash reserves established by our general partner to provide for the properconduct of our business, to comply with applicable law, any of our debtinstruments, or other agreements, or to provide funds for distributions to ourunitholders and to our general partner for any one or more of the next fourquarters. Working capital 

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borrowings are generallyborrowings that are made under the working capital portion of our creditfacility and in all cases are used solely for working capital purposes or topay distributions to partners.

Upon the closing of our initial public offering,affiliates of Harold Hamm, the Hamm Trusts and an affiliate of Randy Moeder,our Chief Executive Officer, received an aggregate of 4,080,000 subordinatedunits. During the subordination period, the common units will have the right toreceive distributions of available cash from operating surplus in an amountequal to the minimum quarterly distribution of $0.45 per quarter, plus anyarrearages in the payment of the minimum quarterly distribution on the commonunits from prior quarters, before any distributions of available cash fromoperating surplus may be made on the subordinated units. The purpose of thesubordinated units is to increase the likelihood that during the subordinationperiod there will be available cash to be distributed on the common units. Thesubordination period will extend until the first day of any quarter beginningafter March 31, 2010 that each of the following tests are met:distributions of available cash from operating surplus on each of theoutstanding common units and subordinated units equaled or exceeded the minimumquarterly distribution for each of the three consecutive, non-overlappingfour-quarter periods immediately preceding that date; the “adjusted operatingsurplus” (as defined in its partnership agreement) generated during each of thethree consecutive, non-overlapping four-quarter periods immediately precedingthat date equaled or exceeded the sum of the minimum quarterly distributions onall of the outstanding common units and subordinated units during those periodson a fully diluted basis and the related distribution on the 2% generalpartner  interest during those periods; and there are no arrearages inpayment of the minimum quarterly distribution on the common units. If theunitholders remove the general partner without cause, the subordination periodmay end before March 31, 2010.

In addition, if the tests for ending the subordinationperiod are satisfied for any three consecutive four-quarter periods ending onor after March 31, 2008, 25% of the subordinated units will convert intoan equal number of common units. Similarly, if those tests are also satisfiedfor any three consecutive four-quarter periods ending on or after March 31,2009, an additional 25% of the subordinated units will convert into an equalnumber of common units. The second early conversion of subordinated units maynot occur, however, until at least one year following the end of the period forthe first early conversion of subordinated units.

We will make distributions of available cash fromoperating surplus for any quarter during any subordination period in thefollowing manner: first, 98% to the common unitholders, pro rata, and 2% to thegeneral partner, until we distribute for each outstanding common unit an amountequal to the minimum quarterly distribution for that quarter; second, 98% tothe common unitholders, pro rata, and 2% to the general partner, until wedistribute for each outstanding common unit an amount equal to any arrearagesin payment of the minimum quarterly distribution on the common units for anyprior quarters during the subordination period; third, 98% to the subordinatedunitholders, pro rata, and 2% to the general partner, until we distribute foreach subordinated unit an amount equal to the minimum quarterly distributionfor that quarter; and thereafter, cash in excess of the minimum quarterlydistributions is distributed to the unitholders and the general partner basedon the percentages below.

Ourgeneral partner, Hiland Partners GP, LLC, is entitled to incentivedistributions if the amount we distribute with respect to any quarter exceedsspecified target levels shown below:

| ** **                      | ** ** | ** **                                 | ** ** | **Marginal Percentage**            | ** ** |
|---------------------------------|------------|--------------------------------------------|------------|-----------------------------------------|------------|
| ** **                      | ** ** | **Total Quarterly Distribution** | ** ** | **Interest in Distributions** | ** ** |
| ** **                      | ** ** | **Target Amount**                     | ** ** | **Unitholders**                         | ** ** | **General Partner** | ** ** |
| Minimum Quarterly  Distribution |       | $0.45                                      |       |                                    | 98         | % |   |   | 2 | % |   |
| First Target  Distribution      |       | Up  to $0.495                              |       |                                    | 98         | % |   |   | 2 | % |   |
| Second Target  Distribution     |       | Above  $0.495 up to $0.5625                |       |                                    | 85         | % |   |   | 15 | % |   |
| Third Target  Distribution      |       | Above  $0.5625 up to $0.675                |       |                                    | 75         | % |   |   | 25 | % |   |
| Thereafter                      |       | Above $0.675                               |       |                                    | 50         | % |   |   | 50 | % |   |

 

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The equity compensationplan information required by Item 201(d) of Regulation S-K in response tothis item is incorporated by reference into “Item 12. Security Ownership ofCertain Beneficial Owners and Management and Related Unitholder Matters,” ofthis annual report on Form 10-K.

***Issuer Purchases of Equity Securities***

We did not repurchase anyof our common units during the fourth quarter of fiscal 2006.

**Item 6.**                        SelectedHistorical Financial and Operating Data

The following table sets forth selected historicalfinancial and operating data of Hiland Partners, LP and our predecessor, CGI asof and for the periods indicated. The selected historical financial data as of December 31,2006 and for the years ended December 31, 2006 and 2005 are derived fromthe audited financial statements of Hiland Partners, LP.  The selected historical financial data for theyears ended December 31, 2004, 2003 and 2002 are derived from the auditedfinancial statements of CGI.

The following table includes the non-GAAP financialmeasures of (1) EBITDA and (2) total segment margin, which consistsof midstream segment margin and compression segment margin. We define EBITDA asnet income (loss) plus interest expense, provision for income taxes anddepreciation, amortization and accretion expense. We define midstream segmentmargin as midstream revenue less midstream purchases. Midstream purchasesinclude the following costs and expenses: cost of natural gas and NGLspurchased by us from third parties, cost of natural gas and NGLs purchased byus from affiliates, and costs of crude oil purchased by us from third parties.We define compression segment margin as the lease payments received under ourcompression facilities lease agreement with CRI which was restructured asdescribed in “Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations—Items Impacting Comparability of OurFinancial Results—Restructuring of Compression Facilities Lease”. For areconciliation of these non-GAAP financial measures to their most directlycomparable financial measures calculated and presented in accordance with GAAP,please refer to the reconciliation following the table below.

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

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The table should be readtogether with “Item 7. Management’s Discussion and Analysis of FinancialCondition and Results of Operations.”

| ** **                                                       | ** ** | ** **                                                                                | ** ** | **Predecessor**                     | ** ** |
|------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                       | ** ** | **Hiland Partners, LP**                                                         | ** ** | **Continental Gas, Inc.** | ** ** |
| ** **                                                       | ** ** | **Year Ended December 31,**                                                | ** ** |
| ** **                                                       | ** ** | **2006**                                                                                  | ** ** | **2005**                            | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                       | ** ** | **(in thousands, except per unit and operating data)** | ** ** |
| **Summary  of Operations Data:**                                 |       |                                                                                      |       |                                |       |   |   |   |   |   |   |
| Total revenues                                                   |       | $                                                                                         | 219,686    |                                | $          | 166,601 |   | $ | 98,296 |   | $ | 76,018 |   | $ | 35,228 |   |
| Operating costs  and expenses:                                   |       |                                                                                      |       |                                |       |   |   |   |   |   |   |
| Midstream purchases (exclusive of items shown  separately below) |       | 156,193                                                                                   |       | 133,089                             |       | 82,532 |   | 67,002 |   | 27,935 |   |
| Operations and maintenance expenses                              |       | 16,071                                                                                    |       | 7,359                               |       | 4,933 |   | 3,714 |   | 3,509 |   |
| Depreciation, amortization and accretion                         |       | 22,130                                                                                    |       | 11,112                              |       | 4,127 |   | 3,304 |   | 2,370 |   |
| Property impairment expense                                      |       | —                                                                                    |       | —                              |       | — |   | 1,535 |   | — |   |
| (Gain) loss on asset sales                                       |       | —                                                                                    |       | —                              |       | (19 | ) | 34 |   | (12 | ) |
| Bad debt expense                                                 |       | —                                                                                    |       | —                              |       | — |   | — |   | 295 |   |
| General and administrative expenses                              |       | 4,994                                                                                     |       | 2,470                               |       | 1,082 |   | 770 |   | 730 |   |
| Total operating costs and expenses                               |       | 199,388                                                                                   |       | 154,030                             |       | 92,655 |   | 76,359 |   | 34,827 |   |
| Operating income (loss)                                          |       | 20,298                                                                                    |       | 12,571                              |       | 5,641 |   | (341 | ) | 401 |   |
| Other income  (expense):                                         |       |                                                                                      |       |                                |       |   |   |   |   |   |   |
| Interest expense                                                 |       | (5,532                                                                                    | )          | (1,942                              | )          | (702 | ) | (473 | ) | (185 | ) |
| Amortization of deferred loan costs                              |       | (407                                                                                      | )          | (484                                | )          | (102 | ) | (24 | ) | — |   |
| Interest income and other                                        |       | 323                                                                                       |       | 192                                 |       | 40 |   | 10 |   | 72 |   |
| Total other income (expense)                                     |       | (5,616                                                                                    | )          | (2,234                              | )          | (764 | ) | (487 | ) | (113 | ) |
| Income (loss) from continuing operations                         |       | 14,682                                                                                    |       | 10,337                              |       | 4,877 |   | (828 | ) | 288 |   |
| Discontinued operations, net                                     |       | —                                                                                    |       | —                              |       | 35 |   | 246 |   | 199 |   |
| Income (loss) before change in accounting principle              |       | 14,682                                                                                    |       | 10,337                              |       | 4,912 |   | (582 | ) | 487 |   |
| Cumulative effect of change in accounting principle              |       | —                                                                                    |       | —                              |       | — |   | 1,554 |   | — |   |
| Net income                                                       |       | $                                                                                         | 14,682     |                                | $          | 10,337 |   | $ | 4,912 |   | $ | 972 |   | $ | 487 |   |
| Net income per limited partner unit—basic(1)                |       | $                                                                                         | 1.37       |                                | $          | 1.33 |   |   |   |   |   |   |   |
| Net income per limited partner unit—diluted(1)              |       | $                                                                                         | 1.36       |                                | $          | 1.32 |   |   |   |   |   |   |   |
| Cash distributions per limited partner unit(2)                   |       | $                                                                                         | 2.74       |                                | $          | 1.83 |   |   |   |   |   |   |   |
| **Balance  Sheet Data (at period end):**                         | ** ** | ** **                                                                                | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Property and equipment, at cost, net                             |       | $                                                                                         | 252,801    |                                | $          | 120,715 |   | $ | 37,075 |   | $ | 38,425 |   | $ | 23,722 |   |
| Total assets                                                     |       | 343,816                                                                                   |       | 193,969                             |       | 49,175 |   | 47,840 |   | 28,058 |   |
| Accounts payable—affiliates                                 |       | 4,412                                                                                     |       | 6,122                               |       | 2,998 |   | 2,814 |   | 2,150 |   |
| Long-term debt, net of current maturities                        |       | 147,064                                                                                   |       | 33,784                              |       | 12,643 |   | 14,571 |   | 3,491 |   |
| Net equity                                                       |       | 167,746                                                                                   |       | 138,589                             |       | 24,510 |   | 21,739 |   | 20,767 |   |
| **Cash  Flow Data:**                                             | ** ** | ** **                                                                                | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net cash flow  provided by (used in):                            |       |                                                                                      |       |                                |       |   |   |   |   |   |   |
| Operating activities                                             |       | $                                                                                         | 39,580     |                                | $          | 8,122 |   | $ | 7,957 |   | $ | 4,464 |   | $ | 4,809 |   |
| Investing activities                                             |       | (158,426                                                                                  | )          | (74,888                             | )          | (5,290 | ) | (17,286 | ) | (5,645 | ) |
| Financing activities                                             |       | 123,045                                                                                   |       | 72,736                              |       | (2,946 | ) | 13,212 |   | 516 |   |
| **Other  Financial Data:**                                       | ** ** | ** **                                                                                | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Midstream segment margin                                         |       | $                                                                                         | 58,674     |                                | $          | 29,295 |   | $ | 15,764 |   | $ | 9,016 |   | $ | 7,293 |   |
| Compression segment margin                                       |       | 4,819                                                                                     |       | 4,217                               |       | — |   | — |   | — |   |
| Total segment margin                                             |       | $                                                                                         | 63,493     |                                | $          | 33,512 |   | $ | 15,764 |   | $ | 9,016 |   | $ | 7,293 |   |
| EBITDA                                                           |       | $                                                                                         | 42,751     |                                | $          | 23,875 |   | $ | 9,843 |   | $ | 4,773 | (3) | $ | 3,042 |   |
| Maintenance capital expenditures                                 |       | $                                                                                         | 3,434      |                                | $          | 2,225 |   | $ | 1,693 |   | $ | 1,769 |   | $ | 1,826 |   |
| Expansion capital expenditures                                   |       | 155,103                                                                                   |       | 72,723                              |       | 3,474 |   | 14,900 |   | 3,244 |   |
| Discontinued operations                                          |       | —                                                                                    |       | —                              |       | 159 |   | 745 |   | 690 |   |
| Total capital expenditures                                       |       | $                                                                                         | 158,537    |                                | $          | 74,948 |   | $ | 5,326 |   | $ | 17,414 |   | $ | 5,760 |   |
| **Operating  Data:**                                             | ** ** | ** **                                                                                | ** ** | ** **                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas sales (MMBtu/d)                                      |       | 66,947                                                                                    |       | 47,096                              |       | 40,560 |   | 37,701 |   | 26,599 |   |
| NGL sales (Bbls/d)                                               |       | 3,347                                                                                     |       | 1,965                               |       | 1,133 |   | 895 |   | 950 |   |
| Natural gas  gathered (MMBtu/d)                                  |       | 85,540                                                                                    |       | —                              |       | — |   | — |   | — |   |

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(1)             Net income per unit is not applicable for periods priorto our initial public offering.

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(2)             Includes our cash distributions of $0.7125 per unitpaid on February 14, 2007 for 2006 and $0.625 per unit paid on February 14,2006 for 2005.

(3)             EBITDA has not been (a) increased for the impactof the $1.5 million non-cash impairment charge for the year ended December 31,2003 or (b) decreased for the $1.6 million cumulative effect of accountingchange for the year ended December 31, 2003.

Thefollowing table presents a reconciliation of the non-GAAP financial measures of(1) EBITDA to the GAAP financial measure of net income and (2) totalsegment margin (which consists of the sum of midstream segment margin andcompression segment margin) to operating income, in each case, on a historicalbasis for each of the periods indicated.

| ** **                                                                | ** ** | ** **                                 | ** ** | **Predecessor**                     | ** ** |
|---------------------------------------------------------------------------|------------|--------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                | ** ** | **Hiland Partners, LP**          | ** ** | **Continental Gas, Inc.** | ** ** |
| ** **                                                                | ** ** | **Year Ended December 31,** | ** ** |
| ** **                                                                | ** ** | **2006**                                   | ** ** | **2005**                            | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                | ** ** | **(in thousands)**                    | ** ** |
| **Reconciliation of EBITDA to Net  Income:**                              |       |                                       |       |                                |       |   |   |   |   |   |   |
| Net income                                                                |       | $                                          | 14,682     |                                | $          | 10,337 |   | $ | 4,912 |   | $ | 972 |   | $ | 487 |   |
| Add:                                                                      |       |                                       |       |                                |       |   |   |   |   |   |   |
| Depreciation,  amortization and accretion                                 |       | 22,130                                     |       | 11,112                              |       | 4,127 |   | 3,304 |   | 2,370 |   |
| Amortization of  deferred loan costs                                      |       | 407                                        |       | 484                                 |       | 102 |   | 24 |   | — |   |
| Interest expense                                                          |       | 5,532                                      |       | 1,942                               |       | 702 |   | 473 |   | 185 |   |
| EBITDA                                                                    |       | $                                          | 42,751     |                                | $          | 23,875 |   | $ | 9,843 |   | $ | 4,773 | (1) | $ | 3,042 |   |
| **Reconciliation  of Total Segment Margin to****Operating Income (Loss)** |       |                                       |       |                                |       |   |   |   |   |   |   |
| Operating income  (loss)                                                  |       | $                                          | 20,298     |                                | $          | 12,571 |   | $ | 5,641 |   | $ | (341 | ) | $ | 401 |   |
| Add:                                                                      |       |                                       |       |                                |       |   |   |   |   |   |   |
| Operations and  maintenance expenses                                      |       | 16,071                                     |       | 7,359                               |       | 4,933 |   | 3,714 |   | 3,509 |   |
| Depreciation,  amortization and accretion                                 |       | 22,130                                     |       | 11,112                              |       | 4,127 |   | 3,304 |   | 2,370 |   |
| Property  impairment expense                                              |       | —                                     |       | —                              |       | — |   | 1,535 |   | — |   |
| (Gain) loss on  asset sales                                               |       | —                                     |       | —                              |       | (19 | ) | 34 |   | (12 | ) |
| Bad debt expense                                                          |       | —                                     |       | —                              |       | — |   | — |   | 295 |   |
| General and  administrative expenses                                      |       | 4,994                                      |       | 2,470                               |       | 1,082 |   | 770 |   | 730 |   |
| Total segment margin                                                      |       | $                                          | 63,493     |                                | $          | 33,512 |   | $ | 15,764 |   | $ | 9,016 |   | $ | 7,293 |   |

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(1)          EBITDA has not been (a) increasedfor the impact of the $1.5 million non-cash impairment charge for the yearended December 31, 2003 or (b) decreased for the $1.6 millioncumulative effect of accounting change for the year ended December 31,2003.

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**Item 7.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

You should read thefollowing discussion in conjunction with our Consolidated Financial Statementsand notes thereto included elsewhere in this report.

**Overview**

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

CGI historically owned all of our natural gasgathering, processing, treating and fractionation assets other than our Worlandand Bakken gathering systems and the Kinta Area gathering systems we acquiredon May 1, 2006. Hiland Partners, LLC historically has owned our Worlandgathering system, our compression services assets and the Bakken gatheringsystem. CGI is our predecessor for accounting purposes. As a result, ourhistorical financial statements for periods prior to February 15, 2005 arethe financial statements of CGI.

In connection with our initial public offering, theformer owners of CGI and Hiland Partners, LLC and certain of our affiliates,including our general partner, contributed to us, all of the assets andoperations of CGI, other than a portion of its working capital assets, andsubstantially all of the assets and operations of Hiland Partners, LLC, otherthan a portion of its working capital assets and the assets related to theBakken gathering system, in exchange for an aggregate of 720,000 common unitsand 4,080,000 subordinated units, a 2% general partner interest in us and allof our incentive distribution rights, which entitle the general partner toincreasing percentages of the cash we distribute in excess of $0.495 per unitper quarter.

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

Effective September 1, 2005, we consummated theBakken acquisition pursuant to which we acquired the outstanding membershipinterests in Hiland Partners, LLC, an Oklahoma limited liability company, forapproximately $92.7 million in cash, $35.0 million of which was usedto retire outstanding Hiland Partners, LLC indebtedness. Hiland Partners,LLC’s principal asset is the Bakken gathering system located in easternMontana.

We completed a follow-on offering of 1,630,000 commonunits on November 21, 2005, receiving net proceeds of $66.1 millionincluding our general partner’s contribution of $1.4 million. We used $65.2million of the proceeds from the public offering to repay a portion of creditfacility borrowings we had previously used to fund the acquisition of HilandPartners, LLC.

On May 1, 2006, we acquired Enogex Gas Gathering,L.L.C.’s eastern Oklahoma Kinta Area gathering assets for $96.4 million. Wefinanced the acquisition with $61.2 million of borrowings from our creditfacility and $35.0 million of proceeds from the issuance to our general partnerof 761,714 common units and 15,545 general partner equivalent units at $45.03per unit.

On September 25, 2006, certain affiliatedunitholders contributed (i) all of the membership interests in our generalpartner, which owns the 2% general partner interest and all of the incentivedistribution rights in us and (ii) 1,301,471 common units (including761,714 common units held by our general partner) and 4,080,000 subordinatedunits in us to Hiland Holdings GP, LP, a publicly owned limited partnership (NASDAQ: HPGP), in exchange for 13,550,000 limitedpartner units, representing a 62.7% ownership in 

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Hiland Holdings GP, LP. Hiland Partners GP Holdings, LLC, a Delawarelimited liability company formed on May 10, 2006, is the generalpartner of Hiland Holdings GP, LP.

We are engaged in gathering, compressing, dehydrating,treating, processing and marketing natural gas, fractionating NGLs andproviding air compression and water injection services for oil and gassecondary recovery operations. Our operations are primarily located in theMid-Continent and Rocky Mountain regions of the United States.

We manage ourbusiness and analyze and report our results of operations on a segment basis.Our operations are divided into two business segments:

·       *Midstream Segment,* which is engaged in gathering andprocessing of natural gas primarily in the Mid-Continent and Rocky Mountainregions. Within this segment, we also provide certain related services forcompression, dehydrating, and treating of natural gas and the fractionation ofNGLs. The midstream segment generated 92.4% of our total segment margin for theyear ended December 31, 2006 and 87.4% of our total segment margin for theyear ended December 31, 2005.

·       *Compression Segment,* which is engaged in providing aircompression and water injection services for oil and gas secondary recoveryoperations that are ongoing in North Dakota. The compression segment generated7.6% of our total segment margin for the year ended December 31, 2006 and12.6% of our total segment margin for the year ended December 31, 2005. Wehad no compression segment prior to February 15, 2005.

Our midstream assets consist of 13 natural gasgathering systems with approximately 1,844 miles of gas gatheringpipelines, five natural gas processing plants, three natural gas treatingfacilities and three NGL fractionation facilities. Our compression assetsconsist of two air compression facilities and a water injection plant.

Our results of operationsare determined primarily by five interrelated variables: (1) the volume ofnatural gas gathered through our pipelines; (2) the volume of natural gasprocessed; (3) the volume of NGLs fractionated; (4) the level andrelationship of natural gas and NGL prices; and (5) our current contractportfolio. Because our profitability is a function of the difference betweenthe revenues we receive from our operations, including revenues from theproducts we sell, and the costs associated with conducting our operations,including the costs of products we purchase, increases or decreases in ourrevenues alone are not necessarily indicative of increases or decreases in ourprofitability. To a large extent, our contract portfolio and the pricingenvironment for natural gas and NGLs will dictate increases or decreases in ourprofitability. Our profitability is also dependent upon prices and marketdemand for natural gas and NGLs, which fluctuate with changes in market andeconomic condition and other factors.

***How We Evaluate Our Operations***

Our management uses a variety of financial andoperational measurements to analyze our segment performance. These measurementsinclude the following: (1) natural gas and NGL sales volumes, throughputvolumes and fuel consumption by our facilities; (2) total segment margin; (3) operationsand maintenance expenses; (4) general and administrative expenses; and (5) EBITDA.

*Volumesand Fuel Consumption.**  *Naturalgas and NGL sales volumes, throughput volumes and fuel consumption associatedwith our business are an important part of our operational analysis. Wecontinually monitor volumes on our pipelines to ensure that we have adequatethroughput to meet our financial objectives. It is important that wecontinually add new volumes to our gathering systems to offset or exceed thenormal decline of existing volumes that are connected to those systems. Theperformance at our processing, fractionation and treating facilities issignificantly influenced by the volumes of natural gas that flows through oursystems. In addition, we monitor fuel consumption because it has an impact onthe total segment margin realized from our midstream operations and ourcompression services operations.

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*TotalSegment Margin.**  *Weview total segment margin as an important performance measure of the coreprofitability of our operations. We review total segment margin monthly forconsistency and trend analysis.

With respect to our midstream segment, we definemidstream segment margin as our revenue minus midstream purchases. Revenueincludes revenue from the sale of natural gas, NGLs and NGL products resultingfrom our gathering, treating, processing and fractionation activities and fixedfees associated with the gathering of natural gas and the transportation anddisposal of saltwater. Midstream purchases include the cost of natural gas,condensate and NGLs purchased by us from third parties and the cost for thetransportation and fractionation of NGLs by third parties. Our midstreamsegment margin is impacted by our midstream contract portfolio, which isdescribed in more detail below.

With respect to our compression segment, following therestructuring of our lease arrangement to become a service arrangement inconnection with our initial public offering as described in “—Items ImpactingComparability of Our Financial Results,” our compression segment margin equalsthe fee we earn under our Compression Services Agreement with CRI for providingair compression and water injection services. The fee that we earn under thisagreement is fixed so long as our facilities meet specified availabilityrequirements, regardless of CRI’s utilization. As a result, our compressionsegment margin is dependent on our ability to meet their utilization levels.For a discussion of this agreement, please read “—Our Contracts—CompressionServices Agreement.”

*Operationsand Maintenance Expenses.**  *Operations and maintenance expenses are costsassociated with the operation of a specific asset. Direct labor, insurance, advalorem taxes, repair and maintenance, utilities and contract services comprisethe most significant portion of our operations and maintenance expenses. Theseexpenses remain relatively stable independent of the volumes through oursystems but fluctuate slightly depending on the activities performed during aspecific period.

*Generaland Administrative Expenses.**  *Our general and administrative expenses include thecost of employee and officer compensation and related benefits, office leaseand expenses, professional fees, information technology expenses, as well asother expenses not directly associated with our field operations.

Our general and administrative expenses have increasedas a result of our becoming a public company, combined with an increased needfor corporate office employees as a result of acquisitions and internal growth.These expenses were approximately $5.0 million for 2006, $2.5 million for2005 and $1.1 million for 2004. These increases were primarily due toincreased wages and benefits as a result of growth, costs of tax returnpreparations, filing annual and quarterly reports with the Securities andExchange Commission, investor relations, directors’ and officers’ insurance andregistrar and transfer agent fees.

In the omnibus agreement we entered into with CRI inconnection with our initial public offering on February 15, 2005, CRIagreed to provide technology support and human resource functions to us for twoyears, at the lower of CRI’s cost to provide the services or $50,000 per year. Duringthe third quarter of 2006, we hired a director of information technology and adirector of human resources and transitioned these services away from CRI.

*EBITDA.**  *We define EBITDA as net income plusinterest expense, provision for income taxes and depreciation, amortization andaccretion expense. EBITDA is used as a supplemental financial measure by our managementand by external users of our financial statements such as investors, commercialbanks, research analysts and others, to assess:

·       the financial performanceof our assets without regard to financing methods, capital structure orhistorical cost basis;

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·       the ability of our assetsto generate cash sufficient to pay interest costs and support our indebtedness;

·       our operating performanceand return on capital as compared to those of other companies in the midstreamenergy sector, without regard to financing or capital structure; and

·       the viability ofacquisitions and capital expenditure projects and the overall rates of returnon alternative investment opportunities.

EBITDA is also a financialmeasurement that, with certain negotiated adjustments, is reported to ourlenders and is used as a gauge for compliance with some of our financialcovenants under our credit facility. EBITDA should not be considered analternative to net income, operating income, cash flows from operatingactivities or any other measure of financial performance presented inaccordance with GAAP.

***How We Manage Our Operations***

Our management team uses a variety of tools to manageour business. These tools include: (1) flow and transaction monitoringsystems; (2) producer activity evaluation and reporting; and (3) imbalancemonitoring and control.

*Flowand transaction monitoring systems.**  *We utilize a customized system thattracks commercial activity on a daily basis at each of our gathering systems,processing plants and treating and fractionation facilities. We track andmonitor inlet volumes to our facilities, fuel consumption, NGLs and NGLproducts extracted, condensate volumes and residue sales volumes. We alsomonitor daily operational throughput at our air compression and water injectionfacilities.

*Produceractivity evaluation and reporting.**  *We monitor the producer drillingand completion activity in our primary areas of operation to identifyanticipated changes in production and potential new well attachmentopportunities. The continued connection of natural gas production to ourgathering systems is critical to our business and directly impacts ourfinancial performance. We receive weekly summaries of new drilling permits andcompletion reports filed with the state regulatory agencies that govern theseactivities on all of our gathering systems other than the Bakken gathering system.Producers that have dedicated acreage to our Bakken gathering system provide uswith their projected annual drilling schedules, which are updated periodically.Additionally, our field personnel report the locations of new wells in theirrespective areas and anticipated changes in production volumes to supplyrepresentatives and operating personnel at our corporate offices. Theseprocesses enhance our awareness of new well activity in our operating areas andallow us to be responsive to producers in connecting new volumes of natural gasto our pipelines.

*Imbalance monitoring andcontrol.**  *Wecontinually monitor volumes we deliver to pipelines and volumes nominated forsale on pipelines to ensure we remain within acceptable imbalance limits duringa calendar month. We seek to reduce imbalances because of the inherentcommodity risk that results when deliveries and sales of natural gas are notbalanced concurrently.

**Our Contracts**

Because of the significantvolatility of natural gas and NGL prices, our contract mix can have asignificant impact on our profitability. In order to reduce our exposure tocommodity price risk, we pursue arrangements under which we purchase naturalgas from the producers at the wellhead at an index based price less a fixed feeto gather, dehydrate, compress, treat and/or process their natural gas,referred to as fee based arrangements or contracts, where market conditionspermit. Actual contract terms are based upon a variety of factors, includingnatural gas quality, geographical location, the competitive environment at thetime the contract is executed and customer requirements. Our contract mix and,accordingly, our 

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exposureto 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 andother market factors.

***Our Natural Gas Sales Contracts***

Wesell natural gas on intrastate and interstate pipelines to marketing affiliatesof natural gas pipelines, marketing affiliates of integrated oil companies andutilities. We typically sell natural gas on a monthly basis under index relatedpricing terms. In addition, we have the following forward sales contracts tosell natural gas on our Eagle Chief, Matli and Kinta Area gathering systems:

| ** **                              | ** ** | ** ** | ** ** | **Average**          | ** ** |
|-----------------------------------------|------------|------------|------------|----------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Fixed Price** | ** ** |
| **Production period**              | ** ** | ** ** | ** ** | **(MMBtu)**          | ** ** | **(per MMBtu)** | ** ** |
| January 2007  - December 2007 |       | 1,380,000  |       |                 | $          | 6.92 |   |   |
| January 2008 - December 2008  |       | 1,200,000  |       |                 | $          | 8.43 |   |   |
|                                         |            |            |            |                      |            |  |  |  |  |  |

 

We also use cash flowhedges to limit our exposure to changing natural gas prices. Under these hedgeswe settle monthly on the difference between the sales or purchases of futureproduction to or from our counterparty at fixed prices and the price that willbe established on the date of hedge settlement by reference to a specifiedindex price. These hedge contracts cover periods of up to twenty-four monthsfrom the date of the hedge.

***Our NGL Sales Arrangements***

We sell NGLs and NGLproducts 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 sellNGLs and NGL products on a monthly basis under index related pricing terms. Wealso use cash flow hedges to limit our exposure to changing NGL prices. Underthese hedges we settle monthly on the difference between the sales of futureproduction to our counterparty at a fixed price and the price that will beestablished on the date of hedge settlement by reference to a specified indexprice. These hedges cover periods of up to fifteen months from the date of thehedge.

***Hedging Contracts***

To insure that our hedgingfinancial instruments will be used solely for hedging price risks and not forspeculative purposes, we continually review our hedges for compliance with ourhedging policies and procedures. We recognize gains and losses from thesettlement of our hedges in revenue when we either sell or buy the associatedphysical 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 themarket when we either sell or buy the physical residue natural gas or sell thephysical natural gas liquid. All of our hedges are characterized as cash flowhedges as defined in Statement of Financial Accounting Standards No. 133, “Accountingfor Derivative Instruments and Hedging Activities,” as amended. We determinegains or losses on open and closed hedging transactions based upon thedifference between the hedge price and the physical price. For a more detaileddiscussion on our hedging activity, please read commodity price risks includedin 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 ourNGL fractionation activities, we contract under four types of arrangements.Under each of the contracts, we are required to purchase the supplied gas,subject to the demands of our resale purchasers and the operating conditionsand capacity of our facilities. We do not guarantee the purchase of anyparticular quantity of the gas which is available for sale. The supplierdelivers the gas to us 

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at the inlet of ourgathering systems and we obtain title to the gas at the delivery point. The gasdelivered to us is required to meet specified quality requirements.

The following is asummary of the four types of natural gas purchase contracts that accounted forthe largest percentage of volumes purchased for the years ended December 31,2006, 2005 and 2004.

·       *Percentage-of-proceeds arrangements.  *Underpercentage-of-proceeds arrangements, we generally purchase natural gas fromproducers at the wellhead, gather, treat, and process the natural gas, in somecases fractionate the NGLs into NGL products, and then sell the resultingresidue gas and NGLs or NGL products at index related prices. We remit to theproducers an agreed upon percentage of the proceeds for the natural gas and theNGLs. Under these types of arrangements, our revenues and total segment margincorrelate directly with increases or decreases in natural gas and NGL prices.For the years ended December 31, 2006, 2005 and 2004 we purchased 52%, 43%and 33% of our total volumes under these types of fee arrangements,respectively.

·       *Percentage-of-index arrangements.  *Underpercentage-of-index arrangements, we purchase natural gas from the producers atthe wellhead at a price that is at a fixed percentage of the index price forthe natural gas that they produce. We then gather, treat and process thenatural gas, in some cases fractionate the NGLs into NGL products and then sellthe residue gas and NGLs or NGL products pursuant to natural gas or NGLarrangements described above. Since under these types of arrangements our coststo purchase the natural gas from the producer is based on the price of naturalgas, our total segment margin under these arrangements increases as the priceof NGLs increase relative to the price of natural gas, and our total segmentmargin under these arrangements decreases as the price of natural gas increasesrelative to the price of NGLs. For the years ended December 31, 2006, 2005and 2004 we purchased 17%, 25% and 31% of our total volumes under these typesof fee arrangements, respectively.

·       *Fixed-fee arrangements.  *Under fixed-fee arrangements,we purchase natural gas from the producers at the wellhead at an index basedprice less a fixed fee to gather, dehydrate, compress, treat and/or processtheir natural gas. These types of arrangements typically require us to pay theproducer for the value of the wellhead gas less the applicable fee. For theyears ended December 31, 2006, 2005 and 2004 we purchased 31%, 33% and 36%of our total volumes under these types of fee arrangements, respectively.

·       *Fixed-fee**gatheringarrangements.*   Under fixed-fee gathering arrangements, wegather, dehydrate and compress natural gas supplied to our gathering systemsand redeliver the compressed natural gas for a fixed fee. Under thesearrangements, we do not take title to the natural gas. From the period May 1,2006 through December 31, 2006, we gathered an average of 134,140 MMBtu/d,which accounted for 56% of our total volumes.

We are a party to a fixed-fee gas purchase contractwith CRI dated as of August 1, 1999. For the years ended December 31,2006, 2005 and 2004 gas purchased under the contract represented approximately12.5%, 14.0% and 12.9%, respectively of our aggregate natural gas supply. Underthe contract, CRI has committed to supply us with all of the gas that itproduces in a designated area in Blaine County, Oklahoma. The contractcurrently covers approximately 25 wells that are connected to our Matligathering system. We pay CRI the applicable index price for the raw natural gasdelivered to us, less a transportation fee, a processing fee and a treatingfee. The contract remains in effect for the life of the gas leases contained inthe dedicated area. However, we have the right to terminate the contract bygiving 30 days’ notice.

***Compression Services Agreement***

Under the compression servicesagreement that we entered into with CRI in connection with our initial publicoffering and effective as of January 28, 2005, CRI pays us a fixed monthlyfee to provide 

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compressedair and water at pressures sufficient to allow for the injection of either airor water into underground reservoirs for oil and gas secondary recoveryoperations. Under the compression services agreement, CRI is responsible forthe provision to us of power and water to be utilized in the compressionprocess. If our facilities do not meet the monthly volume requirements forcompressed air and water, and the failure is not attributable to CRI’s failureto supply power or water or a force majeure, the fixed monthly payment will bereduced in proportion to the volumes of air or water we were unable to deliverduring such month. CRI may terminate the compression services agreement if weare unable to deliver any compressed air and water for a period of more than 20consecutive days and the failure is not attributable to CRI’s failure to supplypower 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 termsunless terminated by either party by giving notice at least 15 days priorto the end of the then current term.

**Our Growth Strategy**

Our growth strategy contemplates engaging inconstruction and expansion opportunities as well as complementary acquisitionsof midstream assets in our operating areas. We intend to pursue constructionand expansion projects to meet new or increased demand for our midstreamservices. In addition, we intend to pursue acquisitions that we believe willallow us to capitalize on our existing infrastructure, personnel and producerand customer relationships to provide an integrated package of services. We mayalso pursue selected acquisitions in new geographic areas to the extent theypresent growth opportunities similar to those we are pursuing in our existingareas of operations. To successfully execute our growth strategy, we willrequire access to capital on competitive terms. We intend to finance futureacquisitions primarily by using the capacity available under our bank creditfacility and equity or debt offerings or a combination of both.

*CapitalExpenditures.**  *Wemake capital expenditures either to maintain our assets or the supply to ourassets or for expansion projects to increase our total segment margin.Maintenance capital is capital employed to replace partially or fullydepreciated assets to maintain the existing operating capacity of our assetsand to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows.Expansion capital expenditures represent capital expenditures made to expand orincrease the efficiency of the existing operating capacity of our assets.Expansion capital expenditures include expenditures that facilitate an increasein volumes within our operations, whether through construction or acquisition.Expenditures that reduce our operating costs will be considered expansioncapital expenditures only if the reduction in operating expenses exceeds costreductions typically resulting from routine maintenance. Our decisions whetherto spend capital on expansion projects are generally based on the target rateof return, as well as the cash flow capabilities of the assets.

*Acquisitions.**  *In analyzing a particularacquisition, we consider the operational, financial and strategic benefits ofthe transaction. Our analysis includes location of the assets, strategic fit ofthe asset in relation to our business strategy, expertise required to managethe asset, capital required to integrate and maintain the asset, and thecompetitive environment of the area where the assets are located. From afinancial perspective, we analyze the rate of return the assets will generateunder various case scenarios, comparative market parameters and cash flowcapabilities of the assets.

**Items ImpactingComparability of Our Financial Results**

Our historical results ofoperations for the periods presented may not be comparable, either from periodto period or going forward, for the reasons described below.

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***Our Formation***

We were formed in October 2004 to own and operatethe assets that have historically been owned and operated by CGI and HilandPartners, LLC. As part of our formation, immediately prior to consummation ofour initial public offering, the former owners of CGI and Hiland Partners, LLCcontributed to us all of the assets and operations of CGI other than a portionof its working capital assets and all of the assets and operations of HilandPartners, LLC, other than a portion of its working capital assets and theassets 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 hashistorically owned all of our natural gas gathering, processing andfractionation assets other than the Worland and Bakken gathering systems andthe 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 hashistorically owned our Worland gathering system, our Horse Creek compressionfacility, our Cedar Hills water injection plant located next to our Cedar Hillscompression facility and the Bakken gathering system.

***Restructuring of Compression Facilities Lease***

Prior to our initialpublic offering, Hiland Partners, LLC owned our Horse Creek air compressionfacility and our Cedar Hills water injection facility. In 2002, HilandPartners, LLC entered into a five year lease agreement with CRI, pursuant towhich Hiland Partners, LLC leased the facilities to CRI. CRI used its ownpersonnel to operate the facilities, and Hiland Partners, LLC made nooperational decisions. In connection with our formation and our initial publicoffering, we entered into a four-year services agreement with CRI, effective asof January 28, 2005, that replaced the existing lease. Under the servicesagreement, we own and operate the facilities and provide air compression andwater injection services to CRI for a fee. As part of the restructuring, thepersonnel at CRI that operated the facilities were transferred to us. Under thenew services agreement, we receive a fixed payment of approximately$4.8 million per year as compared to $3.8 million per year under theprior lease agreement. In connection with the new services arrangement, weincur approximately $1.0 million per year in additional operating costs.For a description of the restructured agreement, please read “—Our Contracts—CompressionServices Agreement.”

***Construction and Acquisition Activities***

Since our inception, we have grown through acombination 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 theconstruction of a new processing plant in 2006. Additionally, we acquired theWorland gathering system in 2000 and the Carmen gathering system in 2003. Weacquired the Carmen gathering system in 2003 as an expansion of our Eagle Chiefgathering system. Prior to our acquisition of the Carmen gathering system, wepurchased the gas from the previous owner, processed it and returned it to theprevious owner pursuant to a keep-whole arrangement. After we acquired theCarmen gathering system, we terminated this keep-whole arrangement and now sellthe gas at the tailgate of the Eagle Chief processing plant. In addition, wecompleted the Bakken acquisition in September 2005. These historicalacquisitions were completed at different dates and with numerous sellers andwere accounted for using the purchase method of accounting. Under the purchasemethod of accounting, results from such acquisitions are recorded in thefinancial statements only from the date of acquisition.

We acquired the Kinta Area gathering assets in May 2006and operate the gathering assets substantially differently than were operatedby the previous owner. Since there was no sufficient continuity 

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of the Kinta Areagathering assets’ operations prior to and after our acquisition, disclosure ofprior financial information would not be material to an understanding of futureoperations. Therefore, the acquisition has been recorded as a purchase ofassets and not of a business.

We are in the process of expanding our Badlands gasgathering system and processing plant located in Bowman County, North Dakota.This expansion project will include the construction of a 40,000 Mcf/d nitrogenrejection plant, which is expected to be operational by the second quarter of2007, and the expansion of our existing Badlands field-gatheringinfrastructure. We also entered into a five-year definitive purchase agreementwith a producer and have constructed additional compression facilities andexpanded our existing Badlands gas gathering system into South Dakota.

We have installed additional gathering and compressioninfrastructure at our Bakken gathering system to increase the system’s capacityfrom approximately 20,000 Mcf/d to 25,000 Mcf/d and are in the process ofexpanding the existing NGL fractionation facilities at the processing plant tofractionate increased NGL volumes from both the Bakken processing plant and theBadlands processing plant.

We have completed the installation of additionalpipelines and compression facilities and increased our system capacity at ourEagle Chief gathering system from approximately 30,000 Mcf/d to approximately35,500 Mcf/d due to increased volumes on this system. We have also completedthe construction of a 25,000 Mcf/d natural gas processing facility along ourexisting Matli gas gathering system. This new facility provides additionalplant processing capacity for increased system volumes.

We are in the process of installing fouramine-treating facilities at several of our Kinta Area gathering systemlocations to remove excess carbon dioxide levels from the natural gas.

In December 2006, we entered into anagreement to construct and operate gathering pipelines and related facilitiesassociated with the development of a portion of the acreage owned by CRI in theWoodford shale play in the Arkoma Basin of southeastern Oklahoma. We plan tobuild a 40,000 Mcf/d refrigeration processing plant and install field gathering,compression and associated equipment. The new gathering system will be designedto provide low-pressure and highly reliable gathering, compression,dehydration, and processing services. The gathering infrastructure is expectedto include more than 15,500 horsepower of compression to provide takeawaycapacity in excess of 40,000 Mcf/d. Expected startup of the initial phase ofthe project should occur during the second quarter of 2007.

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***Our Results of Operations***

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

Operationsfrom our Worland gathering system and compression assets contributed to us byHiland Partners, LLC are reflected only from February 15, 2005, the dateof our initial public offering. Operations from our acquisition of the Bakkengathering system assets are reflected only from September 1, 2005. Operationsfrom our acquisition of the Kinta Area gathering assets are reflected only fromMay 1, 2006.

| ** **                                                          | ** ** | **Year Ended December 31** | ** ** |
|---------------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                          | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                          | ** ** | ** **                                | ** ** | **Hiland** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                          | ** ** | **Hiland**                                | ** ** | **Partners,** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                          | ** ** | **Partners, LP**                     | ** ** | **LP(1)** | ** ** | **Predecessor(2)** | ** ** | **Total** | ** ** | **Predecessor(2)** | ** ** |
| ** **                                                          | ** ** | **(in thousands)**                   | ** ** |
| **Total Segment Margin Data:**                                      |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Midstream revenues                                                  |       |                                      | $          | 214,867 |   |   | $ | 150,571 |   |   | $ | 11,813 |   |   | $ | 162,384 |   |   | $ | 98,296 |   |   |
| Midstream purchases                                                 |       |                                      | 156,193    |   |   | 123,342 |   |   | 9,747 |   |   | 133,089 |   |   | 82,532 |   |   |
| Midstream segment margin                                            |       |                                      | 58,674     |   |   | 27,229 |   |   | 2,066 |   |   | 29,295 |   |   | 15,764 |   |   |
| Compression revenues(3)                                             |       |                                      | 4,819      |   |   | 4,217 |   |   | — |   |   | 4,217 |   |   | — |   |   |
| Total segment margin(4)                                             |       |                                      | $          | 63,493 |   |   | $ | 31,446 |   |   | $ | 2,066 |   |   | $ | 33,512 |   |   | $ | 15,764 |   |   |
| **Summary of Operations Data:**                                     |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Midstream revenues                                                  |       |                                      | $          | 214,867 |   |   | $ | 150,571 |   |   | $ | 11,813 |   |   | $ | 162,384 |   |   | $ | 98,296 |   |   |
| Compression revenues                                                |       |                                      | 4,819      |   |   | 4,217 |   |   | — |   |   | 4,217 |   |   | — |   |   |
| Total revenues                                                      |       |                                      | 219,686    |   |   | 154,788 |   |   | 11,813 |   |   | 166,601 |   |   | 98,296 |   |   |
| Operating costs and expenses:                                       |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Midstream purchases  (exclusive  of items shown separately   below) |       |                                      | 156,193    |   |   | 123,342 |   |   | 9,747 |   |   | 133,089 |   |   | 82,532 |   |   |
| Operations and  maintenance expenses                                |       |                                      | 16,071     |   |   | 6,579 |   |   | 780 |   |   | 7,359 |   |   | 4,933 |   |   |
| Depreciation and  amortization expenses                             |       |                                      | 22,130     |   |   | 10,600 |   |   | 512 |   |   | 11,112 |   |   | 4,127 |   |   |
| Gain on asset sales                                                 |       |                                      | —     |   |   | — |   |   | — |   |   | — |   |   | (19 | ) |   |
| General and administrative  expenses                                |       |                                      | 4,994      |   |   | 2,304 |   |   | 166 |   |   | 2,470 |   |   | 1,082 |   |   |
| Total operating costs  and  expenses                                |       |                                      | 199,388    |   |   | 142,825 |   |   | 11,205 |   |   | 154,030 |   |   | 92,655 |   |   |
| Operating income                                                    |       |                                      | 20,298     |   |   | 11,963 |   |   | 608 |   |   | 12,571 |   |   | 5,641 |   |   |
| Other income (expense),  net                                        |       |                                      | (5,616     | ) |   | (2,119 | ) |   | (115 | ) |   | (2,234 | ) |   | (764 | ) |   |
| Income (loss) from  continuing operations                           |       |                                      | 14,682     |   |   | 9,844 |   |   | 493 |   |   | 10,337 |   |   | 4,877 |   |   |
| Discontinued operations,  net                                       |       |                                      | —     |   |   | — |   |   | — |   |   | — |   |   | 35 |   |   |
| Net income                                                          |       |                                      | $          | 14,682 |   |   | $ | 9,844 |   |   | $ | 493 |   |   | $ | 10,337 |   |   | $ | 4,912 |   |   |
| Operating Data:                                                     |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Natural gas sales  (MMBtu/d)                                        |       |                                      | 66,947     |   |   | 48,509 |   |   | 37,052 |   |   | 47,096 |   |   | 40,560 |   |   |
| NGL sales (Bbls/d)                                                  |       |                                      | 3,347      |   |   | 2,071 |   |   | 1,206 |   |   | 1,965 |   |   | 1,133 |   |   |
| Natural gas gathered  (MMBtu/d)(5)                                  |       |                                      | 85,540     |   |   | — |   |   | — |   |   | — |   |   | — |   |   |

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(1)          Amounts presented in theHiland Partners, LP column include only the activity for the period beginningon the initial public offering date of February 15, 2005. These amountsinclude the operations of the assets contributed from Hiland Partners, LLC atthe closing of our initial public offering (Worland gathering system andcompression assets).

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(2)*         *Amounts presented in the Predecessorcolumn include only the operations of CGI for the period prior to the initialpublic offering of Hiland Partners, LP on February 15, 2005.

(3)          Compression revenues andcompression segment margin are the same. There are no compression purchasesassociated with the compression segment.

(4)          Reconciliation of totalsegment margin to operating income:

| ** **                                | ** ** | **Year Ended December 31** | ** ** |
|-------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                | ** ** | **2006**                                  | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                | ** ** | ** **                                | ** ** | **Hiland** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                | ** ** | **Hiland**                                | ** ** | **Partners,** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                | ** ** | **Partners, LP**                     | ** ** | **LP(1)** | ** ** | **Predecessor(2)** | ** ** | **Total** | ** ** | **Predecessor(2)** | ** ** |
| ** **                                | ** ** | **(in thousands)**                   | ** ** |
| Operating income                          |       |                                      | $          | 20,298 |   |   | $ | 11,963 |   |   | $ | 608 |   |   | $ | 12,571 |   |   | $ | 5,641 |   |   |
| Add:                                      |       |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Operations and  maintenance  expenses     |       |                                      | 16,071     |   |   | 6,579 |   |   | 780 |   |   | 7,359 |   |   | 4,933 |   |   |
| Depreciation,  amortization and accretion |       |                                      | 22,130     |   |   | 10,600 |   |   | 512 |   |   | 11,112 |   |   | 4,127 |   |   |
| Gain on asset  sales                      |       |                                      | —     |   |   | — |   |   | — |   |   | — |   |   | (19 | ) |   |
| General and  administrative  expenses     |       |                                      | 4,994      |   |   | 2,304 |   |   | 166 |   |   | 2,470 |   |   | 1,082 |   |   |
| Total segment margin                      |       |                                      | $          | 63,493 |   |   | $ | 31,446 |   |   | $ | 2,066 |   |   | $ | 33,512 |   |   | $ | 15,764 |   |   |

 

(5)*         *Natural gas gathered for fee (MMBtu/d)represents natural gas volumes gathered associated with the Kinta Areagathering assets we acquired on May 1, 2006 in which we do not take titleto the gas.

***Year Ended December 31, 2006 Compared with YearEnded 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, anincrease of $53.1 million, or 31.9%. This increase was primarily attributableto (i) increased volumes of 11,799 MMBtu/d of natural gas sales, and 1,267Bbls/d of NGL sales attributable to our acquisition of the Bakken gatheringsystem effective September 1, 2005, (ii) increased volumes ofapproximately 8,428 MMBtu/d of natural gas sales and 127,437 MMBtu/d of naturalgas gathered for the eight months ended December 31, 2006 from the KintaArea gathering assets we acquired on May 1, 2006, (iii) additionalvolumes attributable to the Worland gathering system which was contributed tous on February 15, 2005 and (iv) increased revenues from compressionassets also contributed to us on February 15, 2005.

Midstream revenues were $214.9 million for the yearended 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, $137.6million was attributable to higher residue natural gas and NGL sales volumesoffset by a decrease of $85.1 million attributable to decreased averagerealized natural gas and NGL prices. Increased volumes in 2006 on the Bakkengathering system we acquired effective September 1, 2005 and on the KintaArea gathering assets we acquired on May 1, 2006 represented $41.1 millionand $19.7 million, respectively of the increase in midstream revenues. Thiscombined increase of $60.8 million was primarily offset by a decrease of $8.3million as a result of lower natural sales gas and NGL sales prices in 2006 ascompared to 2005.

Natural gas sales volumes were 66,947 MMBtu/d for theyear ended December 31, 2006 compared to 47,096 MMBtu/d for the year endedDecember 31, 2005, an increase of 19,851 MMBtu/d, or 42.2%. Of the 19,851MMBtu/d increase, 11,799 MMBtu/d, or 59.4% was attributable to natural gasvolumes as a result of our Bakken gathering system acquisition effective September 1,2005 and 5,657 MMBtu/d, or 32.1% was 

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attributable to thenatural gas volumes as a result of our Kinta Area gathering assets we acquiredon May 1, 2006. Our NGL sales volumes were 3,347 Bbls/d for the year endedDecember 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 126Bbls/d also contributed to our overall increase in volumes for 2006 as comparedto 2005.

Average realized natural gas sales prices were $5.64per MMBtu for the year ended December 31, 2006 compared to $7.39 per MMBtufor the year ended December 31, 2005, a decrease of $1.75 per MMBtu, or23.7%. Average realized NGL sales prices were $0.94 per gallon for the yearended December 31, 2006 compared to $1.01 per gallon for the year ended December 31,2005, a decrease of $0.07 per gallon or 6.9%. The decreased in both our averagerealized natural gas sales prices and our NGL sales prices was primarily aresult of lower index prices due to a softening of supply and demandfundamentals for energy, which caused natural gas and crude oil prices to fallduring the year ended December 31, 2006 compared to the year ended December 31,2005.

Cash received from our counterparty on cash flow swapcontracts that began on May 1, 2006 for natural gas derivativetransactions that closed during the year ended December 31, 2006 totaled$3.6 million. This gain increased average realized natural gas sales prices to$5.64 per MMBtu from $5.46 per MMBtu, an increase of $0.18 per MMBtu, or 3.3%. Wehad no closed derivative transactions during the year ended December 31,2005.

Fees earned from an eight-month average of 127,437MMBtu/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 averageof 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 yearended 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 werecontributed to us by Hiland Partners, LLC on February 15, 2005.Accordingly, revenues from these assets were only included for ten and one-halfmonths of the year ended December 31, 2005.

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

***Operations andMaintenance.******  ***Operations and maintenance expensetotaled $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 $8.7million, or 118.4%. Of this increase, $4.6 million, or 53.2% was attributableto operations and maintenance as a result of our Kinta Area gathering assets weacquired on May 1, 2006 and $2.4 million, or 27.2% was attributable tooperations and maintenance at our Bakken gathering system we acquired effectiveSeptember 1, 2005. Higher costs of chemicals and lube oil, combined withincreased wages due to internal expansions caused an increase in operations andmaintenance of $1.5 million in our Eagle Chief, Matli, Badlands andWorland 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 

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December 31, 2005, anincrease 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 gatheringassets we acquired on May 1, 2006 and $4.6 million, or 42.2% wasattributable to depreciation and amortization on our Bakken gathering system weacquired effective September 1, 2005. Depreciation at our Eagle Chief,Matli, Badlands and Worland gathering systems increased by $0.5 million in 2006as compared to 2005 as a result of internal capital expansions completed in2006.

***General andAdministrative.******  ***General and administrativeexpense totaled $5.0 million for the year ended December 31, 2006 comparedwith $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 increasedsalaries and additional staffing of $0.9 million as a result of growth and $0.8million in Sarbanes-Oxley internal control compliance costs and audit and taxpreparation fees.

***Other Income (Expense).***   Otherincome (expense) totaled ($5.6) million for the year ended December 31,2006 compared with ($2.2) million for the year ended December 31, 2005, anincrease in expense of $3.4 million. Interest expense increased $3.6 million. Theincrease is primarily attributable to interest expense associated withborrowings of $61.2 million on our credit facility to partially finance theKinta Area gathering assets we acquired on May 1, 2006, the interestexpense associated with the partial financing of the acquisition of the Bakkengathering system effective September 1, 2005 and additional interestexpense on $62.1 million invested in maintenance and expansion capitalexpenditure projects in 2006 as compared to $10.4 million in 2005.

***Year Ended December 31, 2005 Compared with YearEnded December 31, 2004***

*Revenues.**  *Our total revenues (midstream andcompression) were $166.6 million for the year ended December 31, 2005compared to $98.3 million for the year ended December 31, 2004, anincrease of $68.3 million, or 69.5%. This increase was primarilyattributable to (1) higher average realized natural gas prices and NGLsales prices, (2) increased volumes attributable to the contribution ofthe Worland gathering system by Hiland Partners, LLC on February 15,2005 to us, (3) increased revenues from compression assets contributed byHiland Partners, LLC on February 15, 2005 to us and (4) increasedvolumes attributable to the acquisition of the Bakken gathering systemeffective September 1, 2005.

Our midstream revenues were $162.4 million forthe year ended December 31, 2005 compared to $98.3 million for theyear ended December 31, 2004, an increase of $64.1 million, or 65.2%.Of this increase, $40.9 million was attributable to higher averagerealized natural gas prices and NGL sales prices and $23.2 million wasattributable to higher residue natural gas and NGL sales volumes. The volumeincrease is primarily attributable to the contribution of the Worland gatheringsystem from Hiland Partners, LLC on February 15, 2005 and theacquisition of the Bakken gathering system effective September 1, 2005.

Our natural gas sales volumes were 47,096 MMBtu/dfor the year ended December 31, 2005 compared to 40,560 MMBtu/d forthe year ended December 31, 2004, an increase of 6,536 MMBtu/d, or16.1%. Our NGL sales volumes were 1,965 Bbls/d for the year ended December 31,2005 compared to 1,133 Bbls/d for the year ended December 31, 2004,an increase of 832 Bbls/d, or 73.4%. These increases in volumes areprimarily associated with the contribution of the Worland gathering system fromHiland Partners, LLC on February 15, 2005 and the acquisition of theBakken gathering system from Hiland Partners, LLC effective September 1,2005.

Our average realized natural gas sales prices were$7.39 per MMBtu for the year ended December 31, 2005 compared to $5.49 perMMBtu for the year ended December 31, 2004, an increase of $1.90 perMMBtu, or 34.6%. In addition, average realized NGL sales prices were $1.01 pergallon for the year ended December 31, 2005 compared to $0.76 per gallonfor the year ended December 31, 2004, an increase of $0.25 per gallon or32.9%. The change in our average realized natural gas and NGL sales prices was 

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primarily a result ofhigher index prices due to a tightening of supply and demand fundamentals forenergy, which caused crude oil and natural gas prices to rise during the yearended December 31, 2005 compared to the year ended December 31, 2004.

Our compression revenues were $4.2 million forthe year ended December 31, 2005. The compression assets were contributedby Hiland Partners, LLC on February 15, 2005. CGI, our predecessor,did not have a compression segment, therefore, there were no compressionrevenues reported for the year ended December 31, 2004.

*MidstreamPurchases.**  *Ourmidstream purchases were $133.1 million for the year ended December 31,2005 compared to $82.5 million for the year ended December 31, 2004,an increase of $50.6 million, or 61.3%. This increase is primarilyattributable to increased payments on percent of proceeds and percent of indexproducer contracts as a result of higher average realized natural gas pricesand NGL sales prices, the contribution of the Worland gathering system fromHiland Partners, LLC on February 15, 2005 and the acquisition of theBakken gathering system effective September 1, 2005.

*Operationsand Maintenance.**  *Ouroperations and maintenance expense totaled $7.4 million for the year endedDecember 31, 2005 compared with $4.9 million for the year ended December 31,2004, an increase of $2.4 million, or 49.2%. This increase is primarilyattributable to the contribution of the Worland gathering system and thecompression assets from Hiland Partners, LLC on February 15, 2005 andthe acquisition of the Bakken gathering system from Hiland Partners, LLCeffective September 1, 2005.

*Depreciation,Amortization and Accretion.**  *Our depreciation, amortization and accretion expensetotaled $11.1 million for the year ended December 31, 2005 comparedwith $4.1 million for the year ended December 31, 2004, an increaseof $7.0 million, or 169.3%. This increase is primarily attributable to thecontribution of the Worland gathering system and the compression assets fromHiland Partners, LLC on February 15, 2005 and the acquisition of theBakken gathering system effective September 1, 2005.

*Generaland Administrative.**  *Ourgeneral and administrative expense totaled $2.5 million for the year endedDecember 31, 2005 compared with $1.1 million for the year ended December 31,2004, an increase of $1.4 million, or 128.3%. The increase is primarilyattributable to approximately $0.4 million related expenses for adding staff asa result of our growth and approximately $0.7 million additional costs of beinga public company.

*Other Income (Expense).**  *Our other income (expense) totaled($2.2) million for the year ended December 31, 2005 compared with($0.8) million for the year ended December 31, 2004, a increase inexpense of $1.5 million, or 192.4%. The increase is primarily attributableto additional interest expense and amortization of deferred debt issuance costsassociated with our credit facility relating to the acquisition of the Bakkengathering system effective September 1, 2005.

**General Trends andOutlook**

We expect our business to continue to be affected bythe following key trends. Our expectations are based on assumptions made by us,and information currently available to us. To the extent our underlyingassumptions about or interpretations of available information prove to beincorrect, 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 willcontinue to result in relatively high levels of natural gas-related drilling asproducers seek to increase their level of natural gas production. Although thenumber of U.S. natural gas wells drilled has increased overall in recent years,a corresponding increase in production has not been realized, primarily as aresult of smaller discoveries. We believe that an increase in U.S. drillingactivity and additional sources of supply such as liquefied natural 

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gas imports will berequired for the natural gas industry to meet the expected increased demandfor, and to compensate for the slowing production of, natural gas in the UnitedStates.

A number of the areas in which we operate areexperiencing significant drilling activity as result of recent favorablenatural gas prices, new discoveries and the implementation of new explorationand production techniques. We believe that this higher level of activity willcontinue. We also believe that our Badlands gathering system is located in anarea where ongoing secondary recovery operations will provide us withadditional natural gas volumes.

While we anticipate continued high levels ofexploration and production activities in a number of the areas in which weoperate, fluctuations in energy prices can greatly affect production rates andinvestments by third parties in the development of new oil and natural gasreserves. Drilling activity generally decreases as oil and natural gas pricesdecrease. We have no control over the level of drilling activity in the areasof our operations.

*ProcessingMargins.**  *During2006, our margins increased due to increased volumes but decreased due toreduced natural gas prices and NGL prices, resulting in a net increase inmargins. During 2005 and 2004, we generally have seen our margins increase asnatural gas prices and NGL prices have increased, primarily as a result of ourpercentage-of-proceeds contracts. During 2004 and 2003, this positive impact onour margins was partially offset by the negative impact on our marginsresulting from the price of natural gas increasing relative to the price ofNGLs, primarily as a result of our percentage-of-index contracts. Ourprofitability is dependent upon pricing and market demand for natural gas andNGLs, which are beyond our control and have been volatile.

*Rising Interest Rate Environment.**  *The credit markets recently haveexperienced 50-year record lows in interest rates. If the overall economystrengthens, it is likely that monetary policy will tighten further, resultingin higher interest rates to counter possible inflation. Interest rates onfuture credit facilities and debt offerings could be higher than currentlevels, causing our financing costs to increase accordingly. Although thiscould limit our ability to raise funds in the debt capital markets, we expectto remain competitive with respect to acquisitions and capital projects, as ourcompetitors would face similar circumstances. As with other yield orientedsecurities, our unit price is impacted by the level of our cash distributionsand implied distribution yield. The distribution yield is often used byinvestors to compare and rank related yield oriented securities for investmentdecision making purposes. Therefore, changes in interest rates, either positiveor negative, may affect the yield requirements of investors who invest in ourunits, and a rising interest rate environment could have an adverse impact onour 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 Stateshas been relatively low in recent years and did not have a material impact onour results of operations for the periods presented.

**Liquidity andCapital Resources**

***Overview***

Cash generated fromoperations, borrowings under our credit facility and funds from private andfuture public equity and debt offerings are our primary sources of liquidity.We believe that funds from these sources should be sufficient to meet both ourshort-term working capital requirements and our long-term capital expenditurerequirements. Our ability to pay distributions to our unitholders, to fundplanned capital expenditures and to make acquisitions depends upon our futureoperating performance, and more broadly, on the availability of equity and debtfinancing, which will be affected by prevailing economic conditions in ourindustry and financial, business and other factors, some of which are beyondour control.

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***Cash Flows***

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

*CashFlows from Operating Activities.**  *Our cash flows from operatingactivities 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 plusdepreciation and amortization during the year ended December 31, 2006 ascompared to the year ended December 31, 2005. In addition, changes inworking capital items exclusive of cash contributed $2.0 million to cash flowsfrom operating activities during the year ended December 31, 2006 ascompared to reducing cash flows from operating activities by $13.8 million forthe year ended December 31, 2005. The use of cash in operating activitiesin 2005 was primarily a result of replenishing our accounts receivable afterthe closing of our initial public offering and increased accounts receivable asa result of higher realized prices for natural gas and NGLs at December 31,2005. In connection with our formation, $9.1 million of CGI accountsreceivables was retained by former owners of CGI. Accounts receivablesincreased at December 31, 2006 as compared to December 31, 2005 as aresult of receivables related to our acquisition of the Kinta Area gatheringassets, 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, 2006increased due to increased vendor payables relating to internal expansion andgrowth projects and additional accounts payable relating to the operations ofthe Kinta Area gathering assets acquired on May 1, 2006, both of whichwere offset by a reduction in midstream purchases payable due to reducednatural gas and NGL purchase prices at December 31, 2006 as compared tonatural gas and NGL prices at December 31, 2005.

*CashFlows Used for Investing Activities.*   Cash flowsused in investing activities, which represent investments in property andequipment 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 isprimarily a result of the Kinta Area gathering assets acquisition on May 1,2006, the ongoing progress on our Badlands expansion project, continued growthat our Bakken gathering system and various other internal expansion projects.

*Cash Flows from FinancingActivities.**  *Our cash flows from financing activitiesincreased 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 fundthe Kinta Area gathering assets acquisition on May 1, 2006 and to fund ourinternal expansion projects at Badlands, Kinta and Bakken. During the yearended December 31, 2006, we received capital contributions of $35.0million from our general partner in exchange for the issuance of 761,714 commonunits and 15,545 general partner equivalent units and $1.3 million as a resultof 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 debtissuance costs and distributed $25.6 million to our unitholders. We completedour initial public offering of 2,300,000 common units on February 15,2005, receiving net proceeds of $48.1 million. The proceeds from the publicoffering were used to (1) pay remaining offering costs of $2.2 million anddeferred debt issuance costs of $0.6 million, (2) pay outstandingindebtedness of $22.9 million, (3) redeem $6.3 million of common unitsfrom an affiliate of Harold Hamm and the Hamm Trusts, and (4) make a $3.9million distribution to the previous owners of Hiland Partners, LLC. Weretained $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 outstandingindebtedness.

***Year ended December 31, 2005 Compared to Yearended December 31, 2004***

*CashFlows from Operating Activities.**  *Our cash flows from operatingactivities increased by $0.2 million to $8.1 million for the year ended December 31,2005 from $7.9 million for the year ended 

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December 31, 2004. Wereceived cash flows from customers of approximately $143.4 million due to increasedprices for natural gas and NGLs and higher volumes sold in 2005, had cashpayments to our suppliers and employees of approximately $133.9 and payment ofinterest expense of $1.4 million, net of amounts capitalized, resulting in cashreceived from our operating activities of approximately $8.1 million. Changesin cash receipts and payments are primarily due to the timing of collections atthe end of our reporting periods. We collect and pay large receivables andpayables at the end of each calendar month and the timing of these payments andreceipts may vary by a day or two between month-end periods, causing thesefluctuations. Increased natural gas and natural gas liquids prices togetherwith the acquisition of the Bakken assets contributed to increases in accountsreceivable, accrued midstream revenues, accounts payable and accrued midstreampurchases during 2005. In connection with our formation, $9.1 million ofaccounts receivables of CGI was retained by the former owners of CGI. Netincome for the year ended December 31, 2005 was $10.3 million, anincrease of $5.4 million from a net income of $4.9 million for theyear ended December 31, 2004. Our non-cash expenses increased by$7.3 million to $11.6 million in 2005 from $4.3 million in 2004.

*CashFlows Used for Investing Activities.**  *Our cash flows used for investingactivities, which represent investments in property and equipment, increased by$69.6 million to $74.9 million for the year ended December 31,2005 from $5.3 million for the year ended December 31, 2004. Ouracquisition of the Bakken gathering system assets totaled approximately$64.6 million.

*CashFlows from Financing Activities.**  *Our cash flows from financingactivities increased to $72.7 million for the year ended December 31,2005 from ($2.9) million for the year ended December 31, 2004. Wecompleted our initial public offering of 2,300,000 common units on February 15,2005, receiving net proceeds of $48.1 million. The proceeds from thepublic offering were used to (1) pay remaining offering costs of$2.2 million and deferred debt issuance costs of $0.6 million, (2) payoutstanding indebtedness of $22.9 million, (3) redeem$6.3 million of common units from an affiliate of Harold Hamm and the HammTrusts, and (4) make a $3.9 million distribution to the previousowners of Hiland Partners, LLC. We retained $12.2 million to replenishworking capital. During the period from January 1, 2005 to February 14,2005, CGI repaid $1.1 million of its outstanding indebtedness. On September 26,2005, we borrowed $93.7 million under our amended credit facility inconnection with our acquisition of Hiland Partners, LLC and incurred anadditional $0.5 million in debt issuance costs by amending our creditfacility. In addition, our cash flows from financing activities for the yearended December 31, 2005 reflect a $27.8 million distribution to thecontrolling member of our general partner in connection with the acquisition ofHiland Partners, LLC. The controlling member of our general partner owned 49%of Hiland Partners, LLC. The $27.8 million distribution presented in ourstatement of cash flows reflects the difference in the purchase price paid tothe controlling member of our general partner and his cost basis in the netassets of Hiland Partners, LLC. During the third quarter our general partnercontributed $7,000 to maintain its 2% interest in us as a result of ourissuance of 8,000 restricted common units to non-employee board members of ourgeneral partner. On November 21, 2005, we completed our follow-on publicoffering of 1,630,000 common units, receiving net proceeds, including a $1.4million contribution from our general partner to maintain its 2% interest inus, less underwriter discount of $3.4 million, of $66.1 million. Offering costsassociated with our follow-on public offering totaled $0.6 million. Concurrentwith the closing of our secondary public offering, we repaid $65.2 million ofour credit facility borrowings we had previously used to fund the Bakkenacquisition. During the fourth quarter of 2005, we borrowed $5.3 million underour credit facility to fund capital expansion projects. From February 15,2005 through December 31, 2005, we distributed $8.3 million to ourunitholders.

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***CapitalRequirements***

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 willcontinue to be:

·       maintenance capitalexpenditures, which are capital expenditures made to replace partially or fullydepreciated assets to maintain the existing operating capacity of our assetsand to extend their useful lives, or other capital expenditures that areincurred in maintaining existing system volumes and related cash flows; and

·       expansion capitalexpenditures such as those to acquire additional assets to grow our business,to expand and upgrade gathering systems, processing plants, treating facilitiesand fractionation facilities and to construct or acquire similar systems orfacilities.

Given our objectiveof growth through acquisitions and expansions, we anticipate that we willcontinue to invest significant amounts of capital to grow and acquire assets.We actively consider a variety of assets for potential acquisitions. For adiscussion of the primary factors we consider in deciding whether to pursue aparticular acquisition, please read “—Our Growth Strategy—Acquisitions.”

*Total Contractual CashObligations.**  *Asummary of our total contractual cash obligations as of December 31, 2006,which include expansion projects on our Badlands and Kinta Area gatheringsystems, is presented below:

| ** **                                   | ** ** | **Payment Due by Period** | ** ** |
|----------------------------------------------|------------|------------------------------------------|------------|
| ** **                                   | ** ** | **Total**                                | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | ** ** | ** ** |
| **Type of Obligation**             | ** ** | ** **                               | ** ** | **Obligation** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** |
| ** **                                   | ** ** | **(in thousands)**                  | ** ** |
| Senior secured  revolving credit facility(1) |       | $                                        | 147,064    |   | $ | — |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 147,064 |   |   | $ | — |   |   |
| Contracts on  internal expansion projects(2) |       | 12,532                                   |       | 11,203 |   |   | 326 |   |   |   | 325 |   |   |   | 326 |   |   | 325 |   |   | 27 |   |   |
| Operating leases  and service  agreements    |       | 1,423                                    |       | 774 |   |   | 278 |   |   |   | 138 |   |   |   | 83 |   |   | 49 |   |   | 101 |   |   |
| Total contractual cash  obligations          |       | $                                        | 161,019    |   | $ | 11,977 |   |   | $ | 604 |   |   |   | $ | 463 |   |   |   | $ | 409 |   |   | $ | 147,438 |   |   | $ | 128 |   |   |
|                                              |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)          For a discussion of oursenior secured revolving credit facility, please read “—Credit Facility” below.

(2)          Internal ExpansionProjects

*BadlandsExpansion Project.**  *OnNovember 8, 2005, we entered into a new 15-year definitive gaspurchase agreement with CRI under which we will gather, treat and processadditional natural gas, which is produced as a by-product of CRI’s secondaryoil recovery operations, in the areas specified by the contract. In order tofulfill our obligations under the agreement, we intend to expand our Badlandsgas gathering system and processing plant located in Bowman County, North Dakota. This expansion project will includethe construction of a 40,000 Mcf/d nitrogen rejection plant and theexpansion of our existing Badlands field gathering infrastructure. Theexpansion project, which is targeted for completion in the second quarter of2007, is expected to cost approximately $49.5 million, including anadditional $9.5 million to be invested later in 2007 to expand the system.We are currently funding this expansion project using our existing bank creditfacility. Commitments on contracts related to the Badlands expansion projectincluded in the table above are approximately $5.9 million. The cost to expandthe system may exceed our expected costs if our assumptions as to constructioncosts or other factors are incorrect or as a result of other events that arebeyond our control.

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*KintaArea Treating Facilities.**  *We are in the process of installingfour amine-treating facilities at several of our Kinta Area gathering systemlocations to remove excess carbon dioxide from the natural gas. We are alsoinstalling additional compression facilities to expand the current capacity byapproximately 3,000 Mcf/d on these gathering systems. We will invest approximately $6.0 million on these projects andexpect that the projects will be completed by the end of the first quarter of2007. Commitments on contracts related to these projects included in the tableabove are approximately $4.1 million. The cost to expand the system may exceedour expected costs if our assumptions as to construction costs or other factorsare incorrect or as a result of other events that are beyond our control.

*FinancialDerivatives and Commodity Hedges.**  *We have entered into certainfinancial derivative instruments that are classified as cash flow hedges inaccordance with SFAS No. 133, as amended, and relate to forecasted salesin 2007 and 2008. We entered into these instruments to hedge the forecastednatural gas and NGL sales or purchases against the variability in expectedfuture cash flows attributable to changes in market prices. The swapinstruments are contractual agreements between a counterparty and us toexchange obligations of money as the underlying natural gas or NGLs are sold orpurchased. Under these swap agreements, we either receive or pay a monthly netsettlement that is determined by the difference between a fixed price and afloating price based on certain indices for the relevant contract period forthe agreed upon volumes. The following table provides information about thesefinancial derivative instruments for the periods.

*Fixed Price PhysicalForward Sales Contracts.**  *We have executed various natural gas fixed pricephysical forward sales contracts on approximately 115,000 MMBtu per month for2007 and 100,000 MMBtu per month for 2008 with fixed prices ranging from $4.49to $9.13 per MMBtu in 2007 and $8.43 per MMBtu in 2008. These contracts havebeen designated as normal sales under SFAS No. 133 and are therefore notmarked to market as derivatives. A summary of our fixed price physical forwardsales contracts as of December 31, 2006 is presented in the table below:

| ** **                              | ** ** | ** ** | ** ** | **Average**          | ** ** |
|-----------------------------------------|------------|------------|------------|----------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Fixed Price** | ** ** |
| **Production period**              | ** ** | ** ** | ** ** | **(MMBtu)**          | ** ** | **(per MMBtu)** | ** ** |
| January 2007  - December 2007 |       | 1,380,000  |       |                 | $          | 6.92 |   |   |
| January 2008 - December 2008  |       | 1,200,000  |       |                 | $          | 8.43 |   |   |
|                                         |            |            |            |                      |            |  |  |  |  |  |

 

*Off-Balance SheetArrangements.**  *Wehad no significant off-balance sheet arrangements as of December 31, 2006.

***Credit Facility***

Concurrently with the closing of our initial publicoffering, we entered into a three-year $55.0 million senior securedrevolving credit facility. On September 26, 2005, concurrently with theclosing of the Bakken acquisition, we amended this facility to increase ourborrowing capacity under the facility to $125.0 million. On June 8,2006, we entered into a second amendment to our credit facility to, among otherthings, increase our borrowing base to $200 million and revise certaincovenants. The facility currently consists of a $191.0 million seniorsecured revolving credit facility to be used for funding acquisitions and othercapital expenditures, issuance of letters of credit and general corporate purposes(the “revolving acquisition facility”); and a $9.0 million senior securedrevolving credit facility to be used for working capital and to funddistributions (the “revolving working capital facility”).

In addition, our credit facility provides for anaccordion feature, which permits us, if certain conditions are met, to increasethe size of the revolving acquisition facility by up to an additional$150.0 million and allows for the issuance of letters of credit of up to$15.0 million in the aggregate. The credit facility will mature in May 2011.At that time, the agreement will terminate and all outstanding amountsthereunder will be due and payable.

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Our obligations under the credit facility are securedby substantially all of our assets and guaranteed by us and all of oursubsidiaries, other than our operating company, which is the borrower under thecredit facility.

Indebtedness under the credit facility will bearinterest, at our option, at either (i) an Alternate Base Rate plus anapplicable margin ranging from 50 to 125 basis points per annum or (ii) LIBORplus an applicable margin ranging from 150 to 225 basis points per annum basedon our ratio of consolidated funded debt to EBITDA. The Alternate Base Rate isa rate per annum equal to the greatest of (a) the Prime Rate in effect onsuch day, (b) the base CD rate in effect on such day plus 1.50% and (c) theFederal Funds effective rate in effect on such day plus 1¤2of 1%. A letter of credit fee will be payable for the aggregate amount ofletters of credit issued under the credit facility at a percentage per annumequal to 1.0%. An unused commitment fee ranging from 25 to 50 basis points perannum based on our ratio of consolidated funded debt to EBITDA will be payableon the unused portion of the credit facility. During any step-up period (asdefined below), the applicable margin with respect to loans under the creditfacility will be increased by 35 basis points per annum and the unusedcommitment fee will be increased by 12.5 basis points per annum.

The credit facilityprohibits us from making distributions to unitholders if any default or eventof default, as defined in the credit facility, has occurred and is continuingor would result from the distribution. In addition, the credit facilitycontains various covenants that limit, among other things, subject to certainexceptions and negotiated “baskets,” our ability to:

·       incur indebtedness;

·       grant liens;

·       make certain loans,acquisitions and investments;

·       make any material changesto the nature of our business;

·       amend our materialagreements, including the Omnibus Agreement; or

·       enter into a merger,consolidation or sale of assets.

The credit facilityalso contains covenants requiring us to maintain:

·       a maximum consolidatedfunded debt to EBITDA ratio of 4.0:1.0, provided that in the event we makecertain permitted acquisitions or capital expenditures, the credit facilityallows this ratio to increase to 4.75:1.0 for the following three fiscalquarters (a “step-up period”); and

·       a minimum interest coverageratio of 3.0:1.0.

The credit facility defines EBITDA as our consolidatednet income, plus income tax expense, interest expense, depreciation andamortization expense, amortization of intangibles and organizational costs,non-cash unit based compensation expense, and adjustments for non-cash gainsand losses on specified derivative transactions and for other extraordinaryitems.

Upon the occurrenceof an event of default under the credit facility, the lenders may, among otherthings, be able to accelerate the maturity of the credit facility and exerciseother rights and remedies as set forth in the credit facility. Each of thefollowing will be an event of default:

·       failure to pay anyprincipal when due or any interest, fees or other amount within 3 business daysof when due;

·       failure of anyrepresentation or warranty to be true and correct in all material respects;

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·       failure to perform orotherwise comply with the covenants in the credit facility or other loandocuments, in certain cases subject to certain grace periods;

·       default by us or any of oursubsidiaries on the payment of any other indebtedness in excess of$1.0 million, or any default in the performance of any obligation orcondition with respect to such indebtedness beyond the applicable grace periodif the effect of the default is to permit or cause the acceleration of theindebtedness;

·       bankruptcy or insolvencyevents involving us, our general partner or our subsidiaries;

·       material default by anyparty to any material agreement, which is not cured within the time periodspecified in the material agreement for cure, that is reasonably expected tohave a material adverse effect;

·       the entry, and failure topay or contest in good faith, of one or more adverse judgments in an aggregateamount of $500,000 or more in excess of third party insurance coverage;

·       a change of control (asdefined in the credit facility); and

·       invalidity of any loandocumentation.

The credit facility limits distributions to ourunitholders to available cash, and borrowings to fund such distributions areonly permitted under the revolving working capital facility. The revolvingworking capital facility is subject to an annual “clean-down” period of 15consecutive days in which the amount outstanding under the revolving workingcapital facility is reduced to zero.

As of December 31,2006, we had $147.1 million outstanding under the credit facility and were incompliance with its financial covenants.

**Recent AccountingPronouncements**

In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159expands opportunities to use fair value measurement in financial reporting andpermits entities to choose to measure many financial instruments and certainother items at fair value. SFAS No. 159 is effective for fiscal yearsbeginning after November 15, 2007. We have not decided if we will earlyadopt SFAS No. 159 or if we will choose to measure any eligible financialassets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157“Fair Value Measurements.” SFAS No. 157 defines fair value as the pricethat would be received to sell an asset or paid to transfer a liability in anorderly transaction between market participants at the measurement date,establishes a framework for measuring fair value in generally acceptedaccounting principles (GAAP) such as fair value hierarchy used to classify thesource of information used in fair value measurements (i.e., market based ornon-market based) and expands disclosure about fair value measurements based ontheir level in the hierarchy. This Statement applies to derivatives and otherfinancial instruments, which Statement 133, *Accountingfor Derivative Instruments and Hedging Activities*, as amended, requiresbe measured at fair value at initial recognition and for all subsequentperiods. This Statement is effective for financial statements issued for fiscalyears beginning after November 15, 2007 and interim periods within thosefiscal years. We will apply the provisions of the Statement prospectively inour first interim period in the fiscal year beginning on January 1, 2008and we do not expect a change in our methodologies of fair value measurements.

In September 2006,the SEC staff issued Staff Accounting Bulletin No. 108, “Considering theEffects of Prior Year Misstatements when Quantifying Misstatements in CurrentYear Financial Statements.” SAB 108 was issued to provide consistency betweenhow registrants quantify financial statement misstatements. Historically, therehave been two widely used methods for quantifying the effects of 

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financialstatement misstatements. These methods are referred to as the “roll-over” and “ironcurtain” method. The roll-over method quantifies the amount by which the currentyear income statement is misstated. Exclusive reliance on an income statementapproach can result in the accumulation of errors on the balance sheet that maynot have been material to any individual income statement, but which maymisstate one or more balance sheet accounts. The iron curtain method quantifiesthe error as the cumulative amount by which the current year balance sheet ismisstated. Exclusive reliance on a balance sheet approach can result indisregarding the effects of errors in the current year income statement thatresults from the correction of an error existing in previously issued financialstatements. SAB 108 established an approach that requires quantification offinancial statement misstatements based on the effects of the misstatement oneach of the company’s financial statements and the related financial statementdisclosures. This approach is commonly referred to as the “dual approach”because it requires quantification of errors under both the roll-over and ironcurtain methods. We applied SAB 108 in connection with the preparation of ourannual financial statements for the year ending December 31, 2006 and wedid not record an adjustment.

**SignificantAccounting Policies and Estimates**

*RevenueRecognition.**  *Revenuesfor sales of natural gas and NGLs product sales are recognized at the time theproduct is delivered and title is transferred. Revenues for compressionservices are recognized when the services under the agreement are performed.Revenues from oil and gas production (discontinued operations) were recorded inthe month produced and title was transferred to the purchaser.

*Depreciationand Amortization.**  *Depreciationof all equipment is determined under the straight-line method using variousrates based on useful lives, 10 to 22 years for pipeline and processingplants, and 3 to 10 years for corporate and other assets. The cost ofassets and related accumulated depreciation is removed from the accounts whensuch assets are disposed of, and any related gains or losses are reflected incurrent earnings. Maintenance, repairs and minor replacements are expensed asincurred. Costs of replacements constituting improvement are capitalized.Intangible assets consist of the acquired value of existing contracts to sellnatural gas and other NGLs, compression contracts and identifiable customerrelationships, which do not have significant residual value. The contracts arebeing amortized over their estimated lives of ten years.

*Derivatives.**  *We utilize derivative financialinstruments to reduce commodity price risks. We do not hold or issue derivativefinancial instruments for trading purposes. Statement of Financial AccountingStandards (or SFAS) No. 133, “Accounting for Derivative Instruments andHedging Activities”, which was amended in June 2000 by SFAS No. 138and in May 2003 by SFAS No. 149, establishes accounting and reportingstandards for derivative instruments and hedging activities. It requires thatan entity recognize all derivatives as either assets or liabilities in thestatement of financial condition and measure those instruments at fair value.Derivatives that are not designated as hedges are adjusted to fair valuethrough income. If the derivative is designated as a hedge, depending upon thenature of the hedge, changes in the fair value of the derivatives are eitheroffset against the fair value of assets, liabilities or firm commitmentsthrough income, or recognized in other comprehensive income until the hedgeditem is recognized in income. The ineffective portion of a derivative’s changein fair value is immediately recognized into income. If a derivative no longerqualifies for hedge accounting the amounts in accumulated other comprehensiveincome will be immediately charged to operations.

*AssetRetirement Obligations.**  *SFAS No. 143 “Accounting for Asset RetirementObligations” requires entities to record the fair value of a liability for anasset retirement obligation in the period in which it is incurred and acorresponding increase in the carrying amount of the related long-lived asset.Subsequently, the asset retirement cost is allocated to expense using asystematic and rational method and the liability is accreted to measure thechange in liability due to the passage of time. The primary impact of thisstandard relates to our estimated costs for dismantling and site restoration ofcertain of our plants and pipelines. 

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Estimating future assetretirement obligations requires us to make estimates and judgments regardingtiming, existence of a liability, as well as what constitutes adequaterestoration. We use the present value of estimated cash flows related to ourasset retirement obligation to determine the fair value, generally as estimatedby third party consultants. The present value calculation requires us to makenumerous assumptions and judgments, including the ultimate costs of dismantlingand site restoration, inflation factors, credit adjusted discount rates, timingof settlement and changes in the legal, regulatory, environmental and politicalenvironments. To the extent future revisions to these assumptions impact thepresent value of the existing asset retirement obligation liability, a correspondingadjustment will be required to the related asset. We believe the estimates andjudgments reflected in our financial statements are reasonable but arenecessarily subject to the uncertainties we have just described. Accordingly,any significant variance in any of the above assumptions or factors couldmaterially affect our cash flows.

*Impairmentof Long-Lived Assets.**  *Inaccordance with Statement of Financial Accounting Standards (SFAS) No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets”, we evaluateour long-lived assets, including intangible assets, of identifiable businessactivities for impairment when events or changes in circumstances indicate, inmanagement’s judgment, that the carrying value of such assets may not be recoverable.The determination of whether impairment has occurred is based on management’sestimate of undiscounted future cash flows attributable to the assets ascompared to the carrying value of the assets. If impairment has occurred, theamount of the impairment recognized is determined by estimating the fair valuefor the assets and recording a provision for loss if the carrying value isgreater 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 lessthe cost to sell to determine if impairment is required. Until the assets aredisposed of, an estimate of the fair value is re-determined when related eventsor circumstances change.

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

·       changes in general economicconditions in regions in which the Partnership’s products are located;

·       the availability and pricesof NGL products and competing commodities;

·       the availability and pricesof raw natural gas supply;

·       our ability to negotiatefavorable marketing agreements;

·       the risks that third partyoil and gas exploration and production activities will not occur or besuccessful;

·       our dependence on certainsignificant customers and producers of natural gas; and

·       competition from othermidstream service providers and processors, including major energy companies.

Any significant variance in any of the aboveassumptions or factors could materially affect our cash flows, which couldrequire us to record an impairment of an asset.

*ShareBased Compensation.**  *InOctober 1995 the FASB issued SFAS No. 123, “Share-Based Payment,”which was revised in December 2004 (“SFAS 123R”). SFAS 123R requires thatthe compensation cost relating to share-based payment transactions berecognized in the financial statements and that cost be measured based on thefair value of the equity or liability instruments issued. We adopted 

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SFAS 123R as of January 1,2006 and applied SFAS 123R using the permitted modified prospective methodbeginning as of the same date and our unearned deferred compensation of $289 asof January 1, 2006 has been eliminated against common unit equity. Priorto January 1, 2006 we recorded any unamortized compensation related torestricted unit awards as unearned compensation in equity. We expect no changeto our cash flow presentation from the adoption of SFAS 123R since no taxbenefits are recognized by us as a pass through entity.

We estimate the fair valueof each option granted on the date of grant using the American Binomialoption-pricing model. In estimating the fair value of each option, we use ourpeer group volatility averages as determined on the option grant dates. Wecalculate expected lives of the options under the simplified method asprescribed by the SEC Staff Accounting Bulletin 107 and have used a risk freeinterest rate based on the applicable U.S. Treasury yield in effect at the timeof grant. Our compensation expense for these awards is recognized onthe graded vesting attribution method. Units to be issued under our unitincentive plan may be from newly issued units. Prior to our adoption of SFAS123R on January 1, 2006, we applied Accounting Principles Board Opinion No. 25and related interpretations in accounting for our unit-based compensationawards.

**DisclosureRegarding Forward-Looking Statements**

This annual report on Form 10-K includescertain “forward-looking statements” within the meaning of Section 27A ofthe Securities Act of 1933 and Section 21E of the Securities Exchange Actof 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 webelieve such forward-looking statements are based on reasonable assumptions andcurrent expectations and projections about future events, no assurance can begiven that every objective will be reached.

Actual results maydiffer materially from any results projected, forecasted, estimated orexpressed in forward-looking statements since many of the factors thatdetermine these results are subject to uncertainties and risks, difficult topredict, and beyond management’s control. Such factors include:

·       the general economicconditions in the United States of America as well as the general economicconditions and currencies in foreign countries;

·       the continued ability tofind and contract for new sources of natural gas supply;

·       the amount of natural gastransported on our gathering systems;

·       the level of throughput inour natural gas processing and treating facilities;

·       the fees we charge and themargins realized for our services;

·       the prices and marketdemand for, and the relationship between, natural gas and NGLs;

·       energy prices generally;

·       the level of domestic oiland natural gas production;

·       the availability ofimported oil and natural gas;

·       actions taken by foreignoil and gas producing nations;

·       the political and economicstability of petroleum producing nations;

·       the weather in ouroperating areas;

·       the extent of governmentalregulation and taxation;

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·       hazards or operating risks incidental to thetransporting, treating and processing of natural gas and NGLs that may not befully covered by insurance;

·       competition from other midstream companies;

·       loss of key personnel;

·       the availability and cost of capital and ourability to access certain capital sources;

·       changes in laws and regulations to which we aresubject, including tax, environmental, transportation and employmentregulations;

·       the costs and effects of legal andadministrative proceedings;

·       the ability to successfully identify andconsummate strategic acquisitions at purchase prices that are accretive to theour financial results; and

·       risks associated with the construction of newpipelines and treating and processing facilities or additions to our existingpipelines and facilities.

These factors are notnecessarily all of the important factors that could cause actual results todiffer materially from those expressed in any of our forward-lookingstatements. Our future results will depend upon various other risks anduncertainties, including, but not limited to those described under “Item 7.

Management’s Discussionand Analysis of Financial Condition and Results of Operations—Risk FactorsRelated to our Business.” Other unknown or unpredictable factors also couldhave material adverse effects on our future results. You should not put unduereliance on any forward-looking statements. All forward-looking statementsattributable to us are qualified in their entirety by this cautionary statement.We undertake no duty to update our forward-looking statements.

**Item7A.**                Quantitative andQualitative Disclosures about Market Risk

Market risk is the risk ofloss arising from adverse changes in market rates and prices. The principalmarket risk to which we are exposed is commodity price risk for natural gas andNGLs. 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 byvolatility in prevailing NGL and natural gas prices. Historically, changes inthe prices of most NGL products have generally correlated with changes in theprice of crude oil. NGL and natural gas prices are volatile and are impacted bychanges in the supply and demand for NGLs and natural gas, as well as marketuncertainty. 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 isaffected by the volatility of natural gas and NGL product prices, which couldadversely affect our ability to make distributions to unitholders.” Toillustrate the impact of changes in prices for natural gas and NGLs on ouroperating results, we have provided the table below, which reflects, for theyear ended December 31, 2006, 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. Themagnitude of the impact on total segment margin of changes in natural gas andNGL prices presented may not be representative of the magnitude of the impacton total segment margin for different commodity prices or contract portfolios.Natural gas prices can also affect our profitability indirectly by influencingthe level of drilling activity and related opportunities for our services.

| ** **         | ** ** | ** ** | ** ** | **For the Year Ended December 31, 2006** | ** ** |
|--------------------|------------|------------|------------|------------------------------------------------------------------------|------------|
| ** **         | ** ** | ** ** | ** ** | **Natural Gas Price Change ($/MMBtu)**             | ** ** |
|               |       |       |       |                                                                   | $          | 0.10 |   |   |   | $ | (0.10 | ) |   |
| **NGL Price**      |       | $          | 0.01       |                                                                   |       | $ | 263,000 |   |   |   | $ | 93,000 |   |   |
| **Change ($/gal)** |       | $          | (0.01      | )                                                                      |       | $ | (134,000 | ) |   |   | $ | (356,000 | ) |   |

 

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Wemanage this commodity price exposure through an integrated strategy thatincludes management of our contract portfolio, optimization of our assets andthe use of derivative contracts. As a result of these derivative contracts, wehave hedged a portion of our expected exposure to natural gas prices and NGLprices in 2007 and 2008. We continually monitor our hedging and contractportfolio and expect to continue to adjust our hedge position as conditionswarrant. Thefollowing table provides information about our derivative instruments for theperiods indicated:

| ** **                                                    | ** ** | ** **  | ** ** | ** **    | ** ** | **Fair Value**  | ** ** |
|---------------------------------------------------------------|------------|-------------|------------|---------------|------------|----------------------|------------|
| ** **                                                    | ** ** | **Average** | ** ** | ** **    | ** ** | **Asset**            | ** ** |
| **Description and Production Period**          | ** ** | ** **  | ** ** | **Volume**    | ** ** | **Fixed Price** | ** ** | **(Liability)** | ** ** |
| Natural Gas—Sold  Fixed for Floating Price Swaps         |       | (MMBtu)     |       | (per  MMBtu)  |       |                 |       |   |   |
| January 2007  - December 2007                       |       | 1,620,000   |       |          | $          | 8.03                 |       |   |   | $ | 4,634 |   |   |
| January 2008  - December 2008                       |       | 1,620,000   |       |          | $          | 8.00                 |       |   |   | 1,955 |   |   |
|                                                          |       |        |       |          |       |                 |       |   | $ | 6,589 |   |   |
| Natural Gas—Buy Fixed  for Floating Price Swaps          |       | (MMBtu)     |       | (per  MMBtu)  |       |                 |       |   |   |
| January 2007  - December 2007                       |       | 600,000     |       |          | $          | 8.87                 |       |   |   | $ | (1,625 | ) |   |
| January 2008  - March 2008                          |       | 150,000     |       |          | $          | 8.87                 |       |   |   | (194 | ) |   |
|                                                          |       |        |       |          |       |                 |       |   | $ | (1,819 | ) |   |
| Natural Gas  Liquids—Sold Fixed for Floating Price Swaps |       | (Bbls)      |       | (per  Gallon) |       |                 |       |   |   |
| January 2007  - December 2007                       |       | 152,652     |       |          | $          | 1.13                 |       |   |   | $ | (204 | ) |   |
| January 2008  - March 2008                          |       | 38,163      |       |          | $          | 1.13                 |       |   |   | (97 | ) |   |
|                                                          |       |        |       |          |       |                 |       |   | $ | (301 | ) |   |
|                                                               |            |             |            |               |            |                      |            |  |  |  |  |  |  |  |  |

 

Inaddition to the derivative instruments noted in the table above, we haveexecuted various natural gas fixed price physical forward sales contracts onapproximately 115,000 MMBtu per month for 2007 and 100,000 MMBtu per month for2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and $8.43per MMBtu in 2008. These contracts have been designated as normal sales underSFAS No. 133 and are therefore not marked to market as derivatives. Asummary of our fixed price physical forward sales contracts is presented in thetable below:

| ** **                              | ** ** | ** ** | ** ** | **Average**          | ** ** |
|-----------------------------------------|------------|------------|------------|----------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Fixed Price** | ** ** |
| **Production period**              | ** ** | ** ** | ** ** | **(MMBtu)**          | ** ** | **(per MMBtu)** | ** ** |
| January 2007  - December 2007 |       | 1,380,000  |       |                 | $          | 6.92 |   |   |
| January 2008 - December 2008  |       | 1,200,000  |       |                 | $          | 8.43 |   |   |
|                                         |            |            |            |                      |            |  |  |  |  |  |

 

*InterestRate Risk.**  *Weare exposed to changes in interest rates as a result of our credit facility,which has floating interest rates. As of December 31, 2006, we hadapproximately $147.1 million of indebtedness outstanding under our creditfacility. The impact of a 100 basis point increase or decrease in interestrates on this amount of debt would result in an increase or decrease ininterest expense, and a corresponding decrease or increase in net income ofapproximately $1.5 million annually.

*Credit Risk.**  *Counterparties pursuant to theterms of their contractual obligations expose us to potential losses as aresult of nonperformance. OGE Energy Resources, Inc., Montana-DakotaUtility Company and SemStream, L.P. were our largest customers for the yearended December 31, 2006, accounting for approximately 20%, 15% and 14%,respectively, of our revenues. Consequently, changes within one or more ofthese companies’ operations have the potential to impact, both positively andnegatively, our credit exposure. Our counterparty for all of our derivativeinstruments as of December 31, 2006 is BP Corporation North America, Inc.

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**Item 8.**                        FinancialStatements and Supplementary Data

The See our FinancialStatements beginning on page F-1 for the information required bythis Item.

**Item 9.**                        Changes inand Disagreements on Accounting and Financial Disclosure

None.

**Item 9A.**                Controls andProcedures

**Evaluation ofDisclosure Controls and Procedures**

(a)  Evaluationof disclosure controls and procedures.

Our principal executive officer and principal financialofficer have evaluated, as required by Rule 13a-15(b) under theSecurities Exchange Act of 1934 (the “Exchange Act”), our disclosure controlsand procedures (as defined in Exchange Act Rule 13a-15(e)) as of theend of the period covered by the annual report on Form 10-K. Basedon that evaluation, the principal executive officer and principal financialofficer concluded that the design and operation of our disclosure controls andprocedures are effective in ensuring that information we are required todisclose in the reports that we file or submit under the Exchange Act isrecorded, processed, summarized and reported within the time periods specifiedin the Securities and Exchange Commission’s rules and forms.

(b) Changes ininternal control over financial reporting.

For a six-month periodbeginning May 1, 2006, the accounting processes related to the Kinta Areagathering assets we acquired on that date were performed under a transitionagreement with the seller, Enogex Gas Gathering L.L.C. For this six-monthperiod, internal controls over financial reporting relating to Enogex GasGathering L.L.C.’s accounting processes were reviewed for completeness andaccuracy on a monthly basis. Beginning on November 1, 2006, the accountingprocesses were assumed by us and became subject to the same internal controlsover financial reporting established in our other gathering systems. There havebeen no changes in our internal control over financial reporting (as defined inRule 13a-15(f) under the Exchange Act) that occurred during ourlast fiscal quarter that have materially affected or are reasonably likely tomaterially affect our internal control over financial reporting.

**Internal ControlOver Financial Reporting**

See “Managements Report onInternal Control over financial Reporting on page F-2.

**Item 9B.**               Other Information

There have been no events that occurred in the fourthquarter of 2006 that would need to be reported on Form 8-K that havenot been previously reported.

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**PART III**

**Item 10.**                 Directorsand 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 activitiesare managed by our general partner, Hiland Partners GP, LLC. References to ourdirectors and officers are references to the directors and officers of HilandPartners GP, LLC. Unitholders do not directly or indirectly participate in ourmanagement or operation. Our general partner owes a fiduciary duty to ourunitholders, as limited by our partnership agreement.

Directorsare elected for one-year terms. The following table shows information regardingthe current directors and executive officers of Hiland Partners GP, LLC. OnMarch 14, 2007, we announced that Randy Moeder intends to resign as ChiefExecutive Officer and director of both our general partner and the generalpartner of Hiland Holdings GP, LP to pursue other career opportunities. Mr.Moeder has agreed to remain in such positions for approximately six months.Harold Hamm, Chairman of the board of directors of our general partner, isheading up a committee to secure a replacement for Mr. Moeder.

| **Name**                | ** ** | ** ** | ** ** | **Age**                                                                       | ** ** | **Position with Hiland Partners GP, LLC** |
|-------------------------|------------|------------|------------|-------------------------------------------------------------------------------|------------|-------------------------------------------|
| Harold Hamm             |       | 61         |       | Chairman of the Board of  Directors                                           |
| Randy Moeder            |       | 46         |       | Chief Executive Officer,  President and Director                              |
| Ken Maples              |       | 44         |       | Chief Financial Officer,  Vice President—Finance, Secretary and Director |
| Ron Hill                |       | 56         |       | Vice President—Business  Development                                     |
| Robert Shain            |       | 56         |       | Vice  President—Operations and Engineering                               |
| Michael L. Greenwood    |       | 51         |       | Director                                                                      |
| Edward D. Doherty       |       | 71         |       | Director                                                                      |
| Rayford T. Reid         |       | 58         |       | Director                                                                      |
| Shelby E. Odell         |       | 67         |       | Director                                                                      |
| John T. McNabb, II |       | 62         |       | Director                                                                      |
| Dr. David L. Boren |       | 65         |       | Director                                                                      |

 

***Harold Hamm***waselected Chairman of the Board of Directors of our general partner in October 2004and serves as chairman of the compensation committee of the board of directorsof our general partner. Mr. Hamm has served as President and ChiefExecutive Officer and as a director of CGI since December 1994 and thenserved as Chief Executive Officer and a director to 2004. Since its inceptionin 1967 until October 2005, Mr. Hamm served as President and ChiefExecutive Officer and a director of CRI and currently serves as its ChiefExecutive Officer and Chairman of its board of directors. Mr. Hamm is alsoPresident of the National Stripper Well Association, President and Chairman ofthe executive board of the Oklahoma Independent Petroleum Association and amember of the executive board of the Oklahoma Energy Explorers. In addition, Mr. Hammis the founder and serves as Chairman of the board of directors of SaveDomestic Oil, Inc. and is a director of Complete Production Services, Inc.

***Randy Moeder***waselected Chief Executive Officer, President and a director of our generalpartner in October 2004. Mr. Moeder has been Manager of HilandPartners, LLC since its inception in October 2000. He also has beenPresident of CGI since January 1995 and was Vice President from November 1990to January 1995. Mr. Moeder was Senior Vice President and GeneralCounsel of CRI from May 1998 to August 2000 and was Vice Presidentand General Counsel from November 1990 to April 1998. From January 1988to summer 1990, Mr. Moeder worked in private law practice. From 1982 to1988, Mr. Moeder held various positions with Amoco Corporation. Mr. Moederis a member of the Oklahoma Independent Petroleum Association and the Oklahomaand American Bar Associations. Mr. Moeder 

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holds a Bachelor ofScience degree in accounting from Kansas State University and a doctorate ofjurisprudence from the University of Tulsa. Mr. Moeder is also an inactiveCertified Public Accountant.

***Ken Maples***waselected Chief Financial Officer, Vice President—Finance, Secretary and adirector of our general partner in October 2004. Mr. Maples hasserved as Chief Financial Officer of CGI and Hiland Partners, LLC since February 2004.Mr. Maples was Director of Business Development and Manager of InvestorRelations of CRI from October 2002 to February 2004. From October 1990to October 2002, Mr. Maples held various positions with CallonPetroleum Company. He holds a Bachelor degree in accounting from MississippiState University and a Masters of Business Administration degree from LouisianaState University.

***Ron Hill***waselected as Vice President of Business Development in January 2006.Mr. Hill has spent 29 years in the oil and natural gas industry with a 25-yearfocus in gas processing, midstream gas gathering, transportation and NGLmarketing. From October 2001 until January 2006, Mr. Hill servedas Vice President Gas Supply for Pioneer Gas Pipeline, Inc. in San Angelo,Texas. From November 1991 until October 2001, Mr. Hill wasSenior Representative Business Development for Western Gas Resources, Inc.in Oklahoma City, Oklahoma and Midland, Texas. Prior to November 1991, Mr. Hillserved in a variety of commercial roles for Union Texas Petroleum Corporation,Tipperary Corporation and Texaco, Inc.

***Robert Shain***waselected as our Vice PresidentNorthern Region Operations & Engineering in March 2006 and wasappointed Vice President Operations and Engineering on June 5, 2006. Mr. Shainhas over 30 years in the oil and gas industry. The majority of his experiencehas been in the engineering and operations of midstream natural gas gathering,compression, processing and treating, along with business development andmarketing. From July 2003 until March 2006, Mr. Shain served asVice President of Operations and Engineering for Seminole Gas Company, LLC(successor to Impact Energy, LTD) in Tulsa, Oklahoma. From May 1995 until July 2003Mr. Shain served in a variety of commercial roles, most recently of whichwas Vice President of Commercial Services, for CMS Field Services, LLC(successor to Heritage Gas Services, LLC) also in Tulsa, Oklahoma, in which hewas responsible for the development and management of operating and capitalbudgets.

***Michael L.Greenwood***was elected as a director of our generalpartner in February 2005, and serves as Chairman of the audit committee ofour general partner. Mr. Greenwood is founder and managing director ofCarnegie Capital LLC, a financial advisory services firm providing investmentbanking assistance to the energy industry. Mr. Greenwood previously servedas Vice President—Finance and Treasurer of Energy Transfer Partners, L.P. untilAugust 2004. Prior to its merger with Energy Transfer, Mr. Greenwoodserved as Vice President and Chief Financial Officer & Treasurer ofHeritage Propane Partners, L.P. from 2002 to 2003. Prior to joining HeritagePropane, Mr. Greenwood was Senior Vice President, Chief Financial Officerand Treasurer for Alliance Resource Partners, L.P. from 1994 to 2002. Mr. Greenwoodhas over 20 years of diverse financial and management experience in theenergy industry during his career with several major public energy companiesincluding MAPCO Inc., Penn Central Corporation, and The WilliamsCompanies. Mr. Greenwood also serves as a director of Hiland Holdings GP,LP , Libra Natural Resources plc and Global Power Equipment Group Inc. Mr. Greenwoodholds a Bachelor of Science in Business Administration degree from OklahomaState University and a Master of Business Administration degree from theUniversity of Tulsa.

***Edward D. Doherty***waselected as a director of our general partner in February 2005, and servesas a member of the audit and conflicts committees of the board of directors ofour general partner. Mr. Doherty served as the Chairman and ChiefExecutive Officer of Kaneb Pipe Line Company LLC, the general partner of KanebPipe Line Partners L.P. since its inception in September 1989 until July 2005.Prior to joining Kaneb, Mr. Doherty was President and Chief ExecutiveOfficer of two private companies, which provided restructuring services totroubled companies and was President and Chief Executive Officer ofCommonwealth Oil Refining Company, Inc., a public refining andpetrochemical company. 

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Mr. Doherty holds aBachelor of Arts degree from Lafayette College and a Doctor of Jurisprudencefrom Columbia University School of Law.

***Rayford T. Reid***waselected as a director of our general partner in May 2005, and serves as amember of the compensation committee of the board of directors of our generalpartner. Mr. Reid has more than 30 years of investment banking,financial advisory and commercial banking experience, including 25 yearsfocused on the oil and gas industry. During the last 20 years, Mr. Reidhas served as President of R. Reid Investments Inc., a private investmentbanking firm which exclusively serves companies engaged in the energy industry.Reid Investments specializes in mergers, acquisitions and divestitures andtraditional and non-traditional private placements of debt and equity. Mr. Reidholds a Bachelor of Arts degree from Oklahoma State University and a Master ofBusiness Administration degree from the Wharton School of the University ofPennsylvania.

***Shelby E. Odell***waselected as a director of our general partner in September 2005 and servesas a member of our audit committee of the board of directors of our generalpartner. Mr. Odell has 40 years experience in the petroleum business,including marketing, distribution, acquisitions, innovation of new assetopportunities, and management. From 1974 to 2000, Mr. Odell held severalpositions with Koch Industries. He retired in 2000 as President of KochHydrocarbon Company and Sr. Vice President of Koch Industries. Prior to joiningKoch, Mr. Odell advanced through several positions with Phillips PetroleumCompany. He is a past member of the Board of Directors of the Gas ProcessorsAssociation and holds an Associate Degree in Accounting from Enid BusinessCollege.

***John T. McNabb, II***was elected to serve as a director of our generalpartner in August 2006, and he serves as chairman of the conflictscommittee and as a member of the compensation committee of the board ofdirectors of our general partner. Mr. McNabb is the founder of GrowthCapital Partners, LP, a merchant banking firm that provides financial advisoryservices to middle market companies throughout the United States, and hasserved as the chairman of its board of directors since 1992. Mr. McNabbhas also served as a Principal of Southwest Mezzanine Investments, theinvestment affiliate of Growth Capital Partners, L.P, since 2001. From June 1990to January 1992, he was a Managing Director of Bankers Trust Company,managing commercial banking, investment banking and financial advisoryactivities in the Southwest for Bankers Trust Company, and a director of BTSouthwest, Inc., an affiliate of Bankers Trust New York Corporation. Mr. McNabbcurrently serves on the board of directors of Warrior Energy Services, Inc.and Willbros Group, Inc. He holds a Bachelor of Arts in History and aMasters of Business Administration from Duke University.

***Dr. David L. Boren***waselected to serve as a director of our general partner in August 2006, andhe serves as a member of the conflicts committee of the board of directors ofour general partner. Dr. Boren serves as President of the University ofOklahoma, a position he has held since November of 1994. Prior to becomingPresident of the university, he served in the United States Senate representingOklahoma from 1979 to 1994. During his service in the Senate he was the longestserving Chairman of the U.S. Select Committee on Intelligence. From 1975to 1979 Dr. Boren was Governor of Oklahoma. Before being elected Governor,he served 8 years in the Oklahoma House of Representatives. He engaged in theprivate practice of law from 1969 to 1974. He also served as a professor ofPolitical Sciences at Oklahoma Baptist University from 1970 to 1974. In 1986 Dr. Borenfounded the Oklahoma Foundation for Excellence, a private foundation whichrewards and encourages excellence in public education. He continues to serve asits Chairman. He received his BA degree from Yale University in 1963, hisMaster’s Degree in Economics from Oxford University in 1965 as a Rhodes Scholarand his Juris Doctorate Degree from the University of Oklahoma in 1968. Hepreviously served as a director of ConocoPhillips Inc. and currentlyserves as a director of Texas Instruments, AMR Corporation and TorchmarkCorporation.

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**Board Committees**

The board appoints committees to help carry out itsduties. In particular, the board committees work on key issues in greaterdetail than would be possible at full board meetings. Only non-employeedirectors may serve on the audit, compensation and conflicts committees. Eachcommittee has a written charter. The charters are posted on our Web site andare available free of charge on request to the Secretary at the address givenunder “Contact Us”.

Thetable below shows the current membership of each board committee.

| **Name**                 | ** ** | ** ** | ** ** | **Audit** | ** ** | **Conflicts** | ** ** | **Compensation** |
|--------------------------|------------|------------|------------|-----------|------------|---------------|------------|------------------|
| Mr. Hamm            |       |       |       |      |       | C             |
| Mr. Greenwood       |       | C          |       |      |       |          |
| Mr. Doherty         |       | *          |       |      |       |          |
| Mr. Reid            |       |       |       |      |       | *             |
| Mr. Odell           |       | *          |       |      |       |          |
| Mr. McNabb, II |       |       |       | C         |       | *             |
| Dr. Boren           |       |       |       | *         |       |          |

----

C = Chairman

* = Member

*Audit Committee*

The audit committee of our general partner’s board ofdirectors is comprised of three non-employee members of the board. Thecommittee is appointed by the board of directors to assist the board infulfilling its oversight responsibilities. Its primary responsibility is to monitorthe 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 bymanagement and the board and review procedures for internal auditing. Responsibilities also include theappointment, compensation, retention and oversight of the work of theindependent registered public accounting firm engaged to prepare the auditreport or perform other audit, review or attest services. The committee reviewsproposed audit plans for the year and the coordination of these plans with theindependent registered public accounting firm. The committee also reviewsthe financial statements and other information contained in quarterly andannual Securities and Exchange Commission’s (the “SEC”) reports with managementand the independent registered public accounting firm to determine that theindependent registered public accounting firm is satisfied with the disclosureand content of the financial statements. The committee shall have authority toobtain advice and assistance from internal or external legal, financial andother advisors.

The board has determinedthat all members of the committee are independent within the meaning of boththe SEC rules and the National Association of Securities Dealers, Inc.(“NASDAQ”) listing standards. The board has further determined that all membersare financially literate within the meaning of the NASDAQ standards and that Mr. Greenwoodis an “audit committee financial expert” as defined in the SEC rules.

*Conflicts Committee*

The conflicts committee of our general partner’s boardof directors is comprised of two non-employee members of the board. Thecommittee is appointed by the board of directors of our general partner tocarry out the duties delegated by the board that relate to specific mattersthat the board believes may involve conflicts of interests between us and ouraffiliates, on the one hand and us and any other group member, any partner orany assignee, on the other hand. The committee is composed solely of two 

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independent directors whoare not unitholders, officers or employees of us or our general partner,officers, directors or employees of any affiliate or holders of any ownershipinterest in us other than our common units and who also meet the independenceand experience standards established by NASDAQ and any applicable laws and regulations.

The committee shall advise the board on actions to betaken by us or matters related to us upon request of the board. The committeedetermines if the resolution of such conflicts of interest is fair andreasonable to us. Any matters approved by the conflicts committee will beconclusively deemed to be fair and reasonable to us, approved by all of ourpartners, and not a breach by our general partner of any duties it may owe tous or to our unitholders. In connection with the committee’s resolution of anyconflict of interest, the committee is authorized to consider the relativeinterests of any party to such conflict, agreement, transaction or situationand the benefits and burdens relating to such interest, any customary oraccepted industry practices and any customary or historical dealings with aparticular person. The committee is also authorized to consider any applicablegenerally accepted accounting practices or principles and such additionalfactors as the committee determines in its sole discretion to be relevant,reasonable or appropriate under the circumstances.

With respect to anycontribution of assets to the Partnership in exchange for Partnershipsecurities, the committee, in determining whether the appropriate number ofPartnership securities are being issued, may take into account, among otherthings, the fair market value of the assets, the liquidated and contingentliabilities assumed, the tax basis in the assets, the extent to which tax-onlyallocations to the transferor will protect the existing partners of thePartnership against a low tax basis, and such other factors as the committeedeems relevant under the circumstances. The committee shall have authority toobtain advice and assistance from internal or external legal, financial andother advisors.

*CompensationCommittee*

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

The committee oversees the compensation for our seniorexecutives, including their salary, bonus, and incentive and equity awards. Thecommittee is responsible primarily for reviewing, approving and reporting tothe board on major compensation and benefits plans, policies and programs ofthe company; reviewing and evaluating the performance and approving thecompensation of senior executive officers; and overseeing management developmentprograms, performance assessment of senior executives and succession planning.Other specific duties and responsibilities include: annually reviewing andapproving corporate goals and objectives relevant to the chief executiveofficer (“CEO”) base compensation, incentive-compensation plans andequity-based plans; evaluating the CEO’s performance in light of those goalsand objectives, and recommending to the board either as a committee or togetherwith the other independent directors, the CEO’s compensation levels based onthis evaluation; and producing the required annual report on executivecompensation.

The compensation committeehas the sole authority to retain, amend the engagement with, and terminate anycompensation consultant to be used to assist it in the evaluation of director,CEO or officer compensation. The committee has sole authority to approve theconsultant’s fees and other retention terms and shall have authority to causeus to pay the fees and expenses of such consultants. The committee shall alsohave authority to obtain advice and assistance from internal or external legal,accounting or other advisors, to approve the fees and expenses of such outsideadvisors, and to cause us to pay the fees and expenses of such outsideadvisors.

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**Report of the AuditCommittee for the Year Ended December 31, 2006**

Our management is responsible for our internalcontrols and our financial reporting process. Grant Thornton LLP, ourIndependent Registered Public Accounting Firm for the year ended December 31,2006, is responsible for performing an integrated audit of the effectiveness ofinternal control over financial reporting and management’s assessment thereofand an independent audit of our consolidated financial statements in accordancewith standards of the Public Company Accounting Oversight Board and to issue areport thereon. Our audit committee monitors and oversees these processes. Ouraudit committee, made up of members of our general partner’s Board ofDirectors, recommends to the board of directors the selection of ourindependent registered public accounting firm.

Our audit committee has reviewed and discussed ouraudited consolidated financial statements with our management and theindependent registered public accounting firm. Our audit committee hasdiscussed with Grant Thornton LLP the matters required to be discussed byStatement on Auditing Standards No. 61, as amended, “Communications withAudit Committees,” including that firm’s independence.

Members of the AuditCommittee:Michael L. GreenwoodEdward D. DohertyShelby E. Odell

**Code of Ethics**

Our general partner hasadopted a Financial Officers Code of Ethics applicable to the Chief ExecutiveOfficer and the Chief Financial Officer, Controller and all other seniorfinancial and accounting officers (the “Senior Financial Officers”) with regardto Partnership-related activities. This Code of Ethics contains the policiesthat relate to the legal and ethical standards of conduct that the SeniorFinancial Officers of our general partner are expected to comply with whilecarrying out their duties and responsibilities on behalf of the Company. TheCode of Ethics also incorporates expectations of Senior Financial Officers thatenable us to provide accurate and timely disclosure in our filings with the SECand other public communications. The Code of Ethics is publicly available onour website under the “Governance” section (at www.hilandpartners.com) and isalso available free ofcharge on request to the Secretary at the address given under “Contact Us”.

**Section 16(a) Beneficial Ownership Reporting Compliance**

Based on our records,except as hereinafter set forth, we believe that during 2006 all of suchreporting persons complied with the Section 16(a) filing requirementsapplicable to them.

**Item 11.**                 ExecutiveCompensation

**COMPENSATIONDISCUSSION AND ANALYSIS**

***Compensation Objectives and Philosophy***

The executive compensation program of our generalpartner is designed to enable our general partner to execute our businessobjectives by attracting, retaining, and motivating the highest quality ofexecutive talent and by rewarding superior performance. Performance managementfocuses on building competencies required for our business and achieving thehighest level of contribution from each employee. Our compensation and benefitspolicies and practices are designed to motivate and reward officers andemployees to achieve goals and objectives that are expected to lead tolong-term enhancement of unitholder value, provide total compensation that iscompetitive within the market place and align individual compensation withcompetency and contribution so that performance, tied to measurable 

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objectives and results,will be rewarded appropriately. We identify our marketplace as both publiclytraded companies approximating our revenue and employee size, and the midstreamand pipeline master limited partnerships within our peer group, including AtlasPipeline Partners, LP, Copano Energy, LLC, Crosstex Energy, LP, GlobalPartners, LP, MarkWest Energy Partners, LP, Regency Energy Partners, LP andTransMontaigne Partners, LP. The compensation committee, established in May 2005believes this definition of our marketplace provides a good benchmark foranalyzing the competitiveness of our executive compensation program.

In addition to basesalary, executive officers are compensated on a performance-oriented basisthrough the use of incentive compensation linking both annual and longer-termresults. The annual incentive bonus permits team and individual performance tobe recognized and is based, in part, on an evaluation of the contribution madeby the officer to our performance. Equity compensation awards are included inthe compensation program to reward executive officers for long-term strategicactions that increase our value and thus unitholder value and to link asignificant amount of an executive’s current and potential future net worth toour success. This use of equity compensation directly relates a portion of eachexecutive officer’s long-term remuneration to our unit price, and thereforealigns the executive’s compensation with the interests of other unitholders.The discretionary granting of unit options, as well as the more limited use ofrestricted units, is used to: (1) recognize promotions of executives intopositions of significant responsibilities; (2) recognize significantaccomplishments of executives, particularly as the accomplishments impactgrowth, profits and/or competitive positioning; and (3) attract and retainhigh level executive talent.

***Oversight of Executive Compensation Program***

The compensation committee of our general partneradministers our executive officer compensation program. The compensationcommittee is primarily responsible for reviewing, approving and reporting tothe board on major compensation and benefits plans, policies and programs ofthe Partnership; reviewing and evaluating the performance and approving thecompensation of senior executive officers; and overseeing managementdevelopment programs, performance assessment of senior executives andsuccession planning. Other specific duties and responsibilities include:annually reviewing and approving corporate goals and objectives relevant to thechief executive officer (“CEO”) base compensation, incentive-compensation plansand equity-based plans; evaluating the CEO’s performance in light of thosegoals and objectives, and recommending to the board, either as a committee ortogether with the other independent directors, the CEO’s compensation levelsbased on this evaluation; and producing the required annual report on executivecompensation. The compensation committee annually evaluates the effectivenessof the executive compensation program in meeting its objectives.

The CEO submits annual base compensation,incentive-compensation and equity-based compensation recommendations of seniorexecutive officers below the CEO to the compensation committee based on eachexecutive’s contribution to our performance and each executive’sresponsibilities and management abilities. The compensation committee evaluatescompensation with reference to our financial and non-financial performance andrelative unitholder return for the prior fiscal year, competitive compensationdata of executives of comparable companies in our marketplace, subjectiveevaluation of each executive’s contribution to our performance and eachexecutive’s experience, responsibilities and management abilities. Thecompensation committee annually advises the board on the compensation to bepaid to the executive officers and approves the compensation for executiveofficers.

The compensation committeehas the sole authority to retain, amend the engagement with, and terminate anycompensation consultant to be used to assist it in the evaluation of director,CEO and executive officer compensation, as appropriate. The committee has soleauthority to approve the consultant’s fees and other retention terms and shallhave authority to cause us to pay the fees and expenses of such consultants. Thecommittee shall also have authority to obtain advice and assistance from 

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internalor external legal, accounting or other advisors, to approve the fees andexpenses of such outside advisors, and to cause us to pay the fees and expensesof such outside advisors. The compensation committee did not engage a compensationconsultant to assist it in determining executive compensation for our fiscalyear ending December 31, 2006.

***Elements ofCompensation***

Our general partner’sexecutive compensation program currently consists of the following elements:

·       basesalaries;

·       annualincentive cash bonus; and

·       long-term incentivecompensation.

*Base Salaries*

Base salary for executive officers is determinedannually by an assessment of our overall performance, executive officerperformance, changes in executive officer responsibilities and relevantmarketplace data. While many aspects of performance can be measured infinancial terms, the compensation committee also evaluates senior management inareas of performance that are more subjective. These areas include the developmentand execution of strategic plans, the exercise of leadership in the developmentof management and other employees, innovation and improvement in our businessactivities, as well as the executive’s involvement in industry groups and inthe communities that we serve. Our general partner seeks to compensateexecutives for their performance throughout the year with annual base salariesthat are fair and competitive within our marketplace. Our general partnerbelieves that executive base salaries should be targeted near the median of therange of salaries for executives in similar positions and with similarresponsibilities at comparable companies in line with our compensationphilosophy, depending on level of competency and contribution of each executive.Individual salaries are generally established in alignment with this target toensure the attraction, development and retention of superior talent, as well asin relation to individual executive performance. Base salaries are reviewedannually to ensure continuing consistency with market levels and our level offinancial performance during the previous fiscal year. Future adjustments tobase salaries and salary ranges will reflect average movement in thecompetitive market as well as individual performance.

Base salaries in 2006 forthe CEO, the Chief Financial Officer (“CFO”) and the past Vice President ofOperations and Engineering were established in November 2005 and were setbased on (1) the financial results of our first nine months of operationsbeginning on February 15, 2005, (2) base salaries of executiveofficers within our marketplace and (3) a subjective evaluation of eachexecutive’s contribution to our performance and each executive’s experience,responsibilities and management abilities. As such, annual base salariesestablished for the CEO, the CFO and the past Vice President of Operations andEngineering for the period from November 2005 through October 2006were $$225,000, $190,000 and $160,000, respectively. Also in November 2005,base salaries were established for an additional Vice President of Operationsand Engineering ($160,000 per year) and a Vice President of BusinessDevelopment ($150,000 per year) to join our executive management team in early2006, primarily determined by the comparable base salaries of similarexecutives within our marketplace. In November 2006, based on basesalaries of comparable executives of companies within our marketplace,evaluation of each executive’s contribution to our performance and thefinancial results of our operations, the compensation committee set basesalaries of $288,000 for our CEO and $225,000 for our CFO for the period from November 2006through October 2007.

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*Annual IncentiveCash Bonus*

Annual incentive cashbonuses are intended to compensate executive officers for achieving our annualfinancial goals and for achieving measurable individual annual performanceobjectives. Annual cash bonuses are 100% discretionary and are determined byour performance relative to financial goals and individual personal performancegoals. 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’srecommendations. Discretionary cash bonuses awarded to our CEO and CFO of$85,000 and $55,000, respectively in March 2006, were determined based onsimilar bonuses awarded to comparable executives within our marketplace and thesubjective evaluation of each executive’s contribution to our financialperformance and each executive’s responsibilities and management abilities.Discretionary cash bonuses for our four named executive officers are to beaddressed at the compensation committee meeting to be held in March 2007.

*Long-Term IncentiveCompensation*

Our general partner adopted the Hiland Partners, LPLong-Term Incentive Plan for the employees and directors of our general partnerand the employees of its affiliates. The compensation plan is administered bythe compensation committee of our general partner’s board of directors and willcontinue in effect until the earliest of (i) the date determined by theboard of directors of our general partner; (ii) the date that common unitsare no longer available for payment of awards under the plan; or (iii) thetenth anniversary of the plan.

The long-term incentive compensation plan is designedto reward executives and other key employees for the attainment of financialgoals and other performance objectives approved annually by the compensationcommittee and to encourage responsible and profitable growth while taking intoaccount non-routine factors that may be integral to our success. Long-termincentive compensation in the form of equity grants of our common units, suchas incentive unit option grants and grants of restricted units, are used toincent performance that leads to enhanced unitholder value, encourage retentionand closely align the executive’s interests with unitholders’ long-terminterests. Equity grants provide a vital link between the long-term resultsachieved for our unitholders and the rewards provided to executives and otherkey employees. The equity grants we adopted upon the formation of our long-termincentive compensation plan were designed to be comparable with long-termincentive plans of other midstream and pipeline master limited partnerships.

Under the unit option grant agreement, granted optionsof common units vest and become exercisable in one-third increments on theanniversary of the grant date over three years. Vested options are exercisablewithin the option’s contractual life of ten years after the grant date.Restricted units vest in quarterly increments over a four-year period from thedate of issuance. Unvested unit options and restricted units become fullyvested upon the disability, death or termination other than for cause of theholder or a change of control of our general partner. If the holder ceases tobe an officer or employee of our general partner for any other reason, hisunvested unit options or restricted units are forfeited. Unit option awards areless attractive than restricted units to the recipient because the fair valueof the unit option at the grant date is generally less than the fair value ofthe restricted unit at the grant date, which bears no cost to the recipient.Furthermore, unit options, which vest in three years, are generally granted inhopeful anticipation of more immediate increases in unit prices, wherebyrestricted units that vest over a longer four-year period are granted more forunitholder ownership.

The size of the unitoption and restricted unit grants is determined relative to our size and ourmarket, employee qualifications and position, as well as master limitedpartnership peer group data. All grants to executive officers require boardapproval. Neither our general partner nor the compensation committee has aprogram, plan or practice to time options grants to its executives incoordination with the release of 

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materialnonpublic information. Any unit options grants made to non-executive employeestypically will occur concurrently with grants to Named Executive Officers. Allunit options are granted at the fair market value of our units on the date ofgrant. The compensation committee determines the aggregate amounts, terms andtiming of unit option and restricted unit awards. The number of units coveredby each award reflects the executive’s level of responsibility along with pastand anticipated future contributions to us. Initially, based on comparableoptions granted to executives of similar midstream and pipeline master limitedpartnerships at their initial public offerings, the CEO recommended to thechairman of the board the number of options to be granted to executive officersand key employees at our initial public offering in February 2005. In November 2005the compensation committee approved 15,000 and 13,000 unit options to begranted to an additional Vice President of Operations and Engineering and aVice President of Business Development, respectively for vacancies to be filledin early 2006. These unit amounts were determined based on a comparison ofsimilar unit awards granted to companies within our marketplace.

***Employment, Change in Control and Salary ContinuationAgreements***

No employment agreements exist with any employee ofour general partner.

Change in control agreements exist only to the extentof all unexercised unit options and restricted units held by all employees ofour general partner, which, in the event of any of the following become fullyvested and exercisable. Change of control generally shall be deemed to occurupon the occurrence of one or more of the following events: (i) any sale,lease, exchange or other transfer or disposition of all or substantially all ofthe assets of the Partnership to any party not affiliated with the Partnershipand/or any of our affiliates; (ii) the consolidation, reorganization,merger or other transaction pursuant to which more than 50% of the combinedvoting power of the outstanding equity interests in the Partnership cease to bedirectly or indirectly owned by our current majority owner group or theiraffiliate;****or (iii) our general partnerceases to be the general partner of the Partnership.

Our general partnercurrently has no salary continuation agreement, or agreement having similareffect, in place with any employee of our general partner other than the changein 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 generalpartner to our CEO and CFO as compensation for services to be renderedexclusively for the benefit of our general partner. In addition, in connectionwith 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 ourCEO and CFO as consideration for their unvested Class B member interestsin our general partner. The Hiland Holdings GP, LP Class B common unitshave substantially identical rights as Hiland Holdings GP, LP common units and,upon vesting, become convertible at the election of the holder into commonunits. Prior to conversion, the Class B common units are non-transferable.The Class B common units vest in equal increments on February 15,2007 and February 15, 2008. In addition, any unvested Class B commonunits will become fully vested upon the disability, death or termination otherthan for cause of the holder or a change of control of our general partner. Ifeither holder ceases to be an officer or employee of our general partner forany other reason, his unvested Class B common units will be forfeited andtransferred to the Hiland Holdings GP, LP’s contributing parties on a pro ratabasis based on their vested ownership of Hiland Partners GP, LLCimmediately prior to the contribution of those interests in connection withtheir formation. See “RetentionAgreement with Randy Moeder”.

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***Summary Compensation Table***

The following table setsforth information regarding compensation earned by our CEO, our CFO and threeother most highly compensated executive officers employed in 2006:

**SUMMARYCOMPENSATION TABLE**

| ** **                                                                          | ** ** | ** ** | ** ** | **Annual Compensation** | ** ** | **Long-Term Compensation** | ** ** | ** **            | ** ** |
|-------------------------------------------------------------------------------------|------------|------------|------------|------------------------------|------------|---------------------------------|------------|-----------------------|------------|
| **Name and**                                                                   | ** ** | ** ** | ** ** | ** **                   | ** ** | ** **                      | ** ** | **Unit**              | ** ** | **Option** | ** ** | **All Other** | ** ** | ** ** | ** ** |
| **Principal Position**                                                         | ** ** | ** ** | ** ** | **Year**                     | ** ** | **Salary ($)(1)**          | ** ** | **Bonus ($)(2)** | ** ** | **Awards ($)(3)** | ** ** | **Awards ($)(4)** | ** ** | **Compensation ($)** | ** ** | **Total ($)** | ** ** |
| Randy Moeder—President and  Chief Executive Officer                            |       |       | 2006       |                         |       |                            | $          | 231,058               |       |   |   | $ | 85,000 |   |   |   | $ | — |   |   |   | $ | 52,534 |   |   |   | $ | 10,855 |   |   |   | $ | 379,447 |   |   |
| Ken Maples—Vice President—Finance, Secretary and  Chief Financial Officer |       |       | 2006       |                         |       |                            | $          | 192,490               |       |   |   | $ | 55,000 |   |   |   | $ | — |   |   |   | $ | 32,834 |   |   |   | $ | 9,560 |   |   |   | $ | 289,884 |   |   |
| Robert Shain—Vice President of  Operations and Engineering                     |       |       | 2006       |                         |       |                            | $          | 126,151               |       |   |   | $ | 40,000 |   |   |   | $ | 4,071 |   |   |   | $ | 27,858 |   |   |   | $ | 69,950 |   |   |   | $ | 268,030 |   |   |
| Ron Hill—Vice President of  Business Development                               |       |       | 2006       |                         |       |                            | $          | 147,692               |       |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | 37,624 |   |   |   | $ | 3,173 |   |   |   | $ | 188,489 |   |   |
| Clint Duty—Former Vice President of Operations  and Engineering           |       |       | 2006       |                         |       |                            | $          | 46,577                |       |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | 12,325 |   |   |   | $ | 2,598 |   |   |   | $ | 61,500 |   |   |
|                                                                                     |            |            |            |                              |            |                                 |            |                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)                Salary includes base salary and payment in respect ofaccrued vacation, holidays and sick days. Mr. Duty left our employment on April 14,2006.

(2)                Bonuses for Mr. Moeder and Mr. Maples wereawarded in March 2006. Mr. Shain was awarded a sign on bonus of$40,000 on March 20, 2006, his date of hire.

(3)                At the November 10, 2006 compensation committeemeeting, Mr. Shain was awarded 3,000 restricted units at $48.85 per unit,the closing price that day. The restricted units vest in quarterly incrementson the anniversary of the grant date over a period of four years. Periodicdistributions on the restricted units are held in trust by our general partneruntil the units vest.

(4)                Mr. Moeder, Mr. Maples and Mr. Duty weregranted 32,000, 20,000 and 20,000 unit options, respectively, at an exerciseprice of $22.50 per unit on February 10, 2005. The grant date fair valueof $5.11 per unit was determined in accordance with FAS 123R using the AmericanBinomial option-pricing model. Mr. Duty forfeited his remaining unvested13,333 unit options when he left our employment. Mr. Hill was hired on January 5,2006 and was awarded 13,000 unit options at a per unit exercise price of $38.72with a grant date fair value of $4.82 per unit. On March 20, 2006, Mr. Shainwas awarded 15,000 unit options at a per unit exercise price of $40.70 with agrant date fair value of $3.91 per unit. The exercise price of the optionsgranted equaled the market price of the units on the grant date. The fair valueof each option granted, as determined in accordance with FAS 123R, wasestimated on the date of grant using the American Binomial option-pricing model.All unit options vest over a three-year period beginning on their respectivedate of grant.

All other compensationincludes our discretionary contributions to our defined contribution retirementplan under which we make contributions to the plan based on a percentage ofeligible employees’ compensation. Additionally, we paid relocation expenses of$68,104 for Mr. Shain.

***Grants of Plan Based Awards***

The following tableprovides information regarding unit options and restricted units awarded in2006:

**GRANTSOF PLAN BASED AWARDS**

|                | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** ** | **All Other** | ** ** | ** **           | ** ** | ** **          | ** ** |
|----------------|------------|------------|------------|--------------------|------------|---------------------|------------|--------------------|------------|----------------------|------------|---------------------|------------|
| ** **     | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** ** | **Option**         | ** ** | ** **           | ** ** | ** **          | ** ** |
| ** **     | ** ** | ** ** | ** ** | **All Other** | ** ** | ** **          | ** ** | **Awards:**        | ** ** | **Exercise or** | ** ** | **Grant Date** | ** ** |
| ** **     | ** ** | ** ** | ** ** | **Unit**           | ** ** | **Base Price** | ** ** | **Number of** | ** ** | **Base Price**  | ** ** | **Fair Value** | ** ** |
| ** **     | ** ** | ** ** | ** ** | **Awards:**        | ** ** | **of Unit**    | ** ** | **Securities**     | ** ** | **of Option**   | ** ** | **of Option**  | ** ** |
| ** **     | ** ** | **Grant**  | ** ** | **Number of** | ** ** | **Awards**          | ** ** | **Underlying**     | ** ** | **Awards**           | ** ** | **Awards**          | ** ** |
| **Name**       | ** ** | ** ** | ** ** | **Date**           | ** ** | **Units (#)**  | ** ** | **($/Unit)**       | ** ** | **Options (#)** | ** ** | **($/Unit)**        | ** ** | **($/Unit)** | ** ** |
| Mr. Shain |       | 3/20/2006  |       |               | —     |                |       |               | —     |                 |       |                | 15,000     |   |   |   | $ | 40.70 |   |   |   | $ | 3.91 |   |   |
|                |       | 11/10/2006 |       |               | 3,000      |                |       |               | $          | 48.85                |       |                |       | — |   |   |   | — |   |   |   | — |   |   |
| Mr. Hill  |       | 1/5/2006   |       |               | —     |                |       |               | —     |                 |       |                | 13,000     |   |   |   | $ | 38.72 |   |   |   | $ | 4.82 |   |   |
|                |            |            |            |                    |            |                     |            |                    |            |                      |            |                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Mr. Shain and Mr. Hillwere awarded the unit options on each of their respective hire dates. Mr. Shainwas awarded 3,000 restricted units in November 2006.

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***Outstanding Equity Awards at Fiscal Year-End Table***

The following tableprovides information regarding outstanding awards that have been granted, butthe ultimate outcomes of which have not been realized:

**GRANTSOF PLAN BASED AWARDS**

|                | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** ** | **All Other** | ** ** | ** **           | ** ** | ** **          | ** ** |
|----------------|------------|------------|------------|--------------------|------------|---------------------|------------|--------------------|------------|----------------------|------------|---------------------|------------|
| ** **     | ** ** | ** ** | ** ** | ** **         | ** ** | ** **          | ** ** | **Option**         | ** ** | ** **           | ** ** | ** **          | ** ** |
| ** **     | ** ** | ** ** | ** ** | **All Other** | ** ** | ** **          | ** ** | **Awards:**        | ** ** | **Exercise or** | ** ** | **Grant Date** | ** ** |
| ** **     | ** ** | ** ** | ** ** | **Unit**           | ** ** | **Base Price** | ** ** | **Number of** | ** ** | **Base Price**  | ** ** | **Fair Value** | ** ** |
| ** **     | ** ** | ** ** | ** ** | **Awards:**        | ** ** | **of Unit**    | ** ** | **Securities**     | ** ** | **of Option**   | ** ** | **of Option**  | ** ** |
| ** **     | ** ** | **Grant**  | ** ** | **Number of** | ** ** | **Awards**          | ** ** | **Underlying**     | ** ** | **Awards**           | ** ** | **Awards**          | ** ** |
| **Name**       | ** ** | ** ** | ** ** | **Date**           | ** ** | **Units (#)**  | ** ** | **($/Unit)**       | ** ** | **Options (#)** | ** ** | **($/Unit)**        | ** ** | **($/Unit)** | ** ** |
| Mr. Shain |       | 3/20/2006  |       |               | —     |                |       |               | —     |                 |       |                | 15,000     |   |   |   | $ | 40.70 |   |   |   | $ | 3.91 |   |   |
|                |       | 11/10/2006 |       |               | 3,000      |                |       |               | $          | 48.85                |       |                |       | — |   |   |   | — |   |   |   | — |   |   |
| Mr. Hill  |       | 1/5/2006   |       |               | —     |                |       |               | —     |                 |       |                | 13,000     |   |   |   | $ | 38.72 |   |   |   | $ | 4.82 |   |   |
|                |            |            |            |                    |            |                     |            |                    |            |                      |            |                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)          One half, or 10,667 of Mr. Moeder’sunit options vested on February 10, 2007. The remainder vest on February 10,2008.

(2)          One half, or 6,667 of Mr. Maples’unit options vested on February 10, 2007. The remainder vest on February 10,2008.

(3)          Mr. Shain’s optionsvest in one-third annual increments beginning on March 20, 2007. Mr. Shain’srestricted units vest in annual increments over a period of four yearsbeginning on November 10, 2007. The market value of Mr. Shain’srestricted units that have not vested was based on the closing price of $54.70per unit on December 29, 2006.

(4)          One third, or 4,333 of Mr. Hill’soptions vested on January 5, 2007. The remainder vest equally on January 5,2008 and January 5, 2009.

On April 14, 2006, Mr. Dutyleft our employment and forfeited 13,333 unvested unit options issued to him onFebruary 10, 2005.

***Option Exercises and Units Vested Table***

The table presented belowprovides information of the values realized upon the exercise of options during2006 based on the difference between the market price of the underlying unitsat exercise and the exercise or base price of the unit options:

**OPTIONEXERCISES AND UNITS VESTED**

| ** **      | ** ** | **Option Awards** | ** ** |
|-----------------|------------|------------------------|------------|
| ** **      | ** ** | **Number**             | ** ** | **Value** | ** ** |
| ** **      | ** ** | **of Units**      | ** ** | **Realized** | ** ** |
| ** **      | ** ** | **Acquired on**   | ** ** | **Upon** | ** ** |
| **Name**        | ** ** | ** **             | ** ** | **Exercise (#)** | ** ** | **Exercise ($)** | ** ** |
| Mr. Moeder |       |                   | 10,667     |   |   |   | $ | 172,485 |   |   |
| Mr. Maples |       |                   | 6,667      |   |   |   | $ | 110,006 |   |   |
| Mr. Duty   |       |                   | 6,667      |   |   |   | $ | 112,472 |   |   |
|                 |            |                        |            |  |  |  |  |  |  |  |  |  |

 

No restricted unitsgranted to executive officers vested in 2006.

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***DirectorCompensation***

Mr. Harold Hamm, thechairman of the board of directors of our general partner and a non-employeedirector, receives no form of director compensation whatsoever. Similarly, ourCEO, Mr. Moeder and our CFO, Mr. Maples, who are employees of ourgeneral partner, are also non-compensated members of the board of directors ofour general partner. The table below shows the total compensation paid in 2006to each of our current non-employee directors

**DIRECTORCOMPENSATION**

| ** **                  | ** ** | **Annual Base** | ** ** | **Committee**       | ** ** | **Restricted Unit** | ** ** | **Restricted Unit** | ** ** | ** **                    | ** ** |
|-----------------------------|------------|----------------------|------------|---------------------|------------|--------------------------|------------|--------------------------|------------|-------------------------------|------------|
| **Name**                    | ** ** | ** **           | ** ** | **Fee(1) ($)** | ** ** | **Fees ($)**        | ** ** | **Awards(2) ($)**   | ** ** | **Distributions(3) ($)** | ** ** | **Total ($)** | ** ** |
| Michael L.  Greenwood       |       |                 | $          | 31,000              |       |                     |       | $                        | 17,500     |                          |       |   | $ | 44,450 |   |   |   | $ | 1,231 |   |   | $ | 94,181 |   |
| Edward D. Doherty           |       |                 | $          | 31,000              |       |                     |       | $                        | 12,500     |                          |       |   | $ | 44,450 |   |   |   | $ | 1,231 |   |   | $ | 89,181 |   |
| Rayford T. Reid             |       |                 | $          | 31,000              |       |                     |       | $                        | 3,000      |                          |       |   | $ | 44,450 |   |   |   | $ | 1,231 |   |   | $ | 79,681 |   |
| Shelby E. Odell             |       |                 | $          | 31,000              |       |                     |       | $                        | 8,000      |                          |       |   | $ | 46,570 |   |   |   | $ | 1,231 |   |   | $ | 86,801 |   |
| John T.  McNabb, II(4) |       |                 | $          | 28,000              |       |                     |       | $                        | 4,500      |                          |       |   | $ | 88,000 |   |   |   | $ | — |   |   | $ | 120,500 |   |
| Dr. David L.  Boren(4) |       |                 | $          | 28,000              |       |                     |       | $                        | 1,000      |                          |       |   | $ | 88,000 |   |   |   | $ | — |   |   | $ | 117,000 |   |
|                             |            |                      |            |                     |            |                          |            |                          |            |                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)          Includesan annual base fee of $25,000 per director plus $1,500 per director for eachquarterly board of directors meeting attended.

(2)          Thevalue shown is the number of restricted unit granted in 2006 times the closingprice of our units on the day of grant. The value given does not reflect areduction for the fact that the shares are subject to potential forfeiture inthe event the director leaves the board before the four-year vesting period.Three non-employee directors each received 1,000 restricted units on theirfirst anniversary date and two other non-employee directors received 2,000restricted units each on August 11, 2006, the date they were first electedthe board.

(3)          Representsthe aggregate cash distributions paid at the time the units vested on allrestricted units held by the director during 2006.

(4)          Mr. McNabband Dr. Boren were elected to the board on August 11, 2006.

No additional remunerationis paid to officers of our general partner who also serve as directors. Ourindependent directors receive (a) a $25,000 annual cash retainer fee, (b) $1,500for each regularly scheduled meeting attended, (c) $750 for each specialmeeting attended and (d) 2,000 restricted units upon becoming a directorand 1,000 restricted units on each anniversary date of becoming a director. Therestricted units vest in quarterly increments on the anniversary of the grantdate over a period of four years. In addition to the foregoing, each directorwho 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 andthe chairmen of our other committees receive an annual retainer of $2,500. Inaddition, each independent director is reimbursed for his out-of-pocket expensesin connection with attending meetings of the board of directors or committees.Each director is fully indemnified for his actions associated with being adirector to the fullest extent permitted under Delaware law.

***Reimbursement ofExpenses of Our General Partner***

Our general partner willnot receive any management fee or other compensation for its management of ourpartnership. Our general partner and its affiliates will be reimbursed for allexpenses incurred on our behalf. These expenses include the cost of employee,officer and director compensation benefits properly allocable to ourpartnership and all other expenses necessary or appropriate to the conduct ofour business and allocable to us. The partnership agreement provides that ourgeneral partner will determine the expenses that are allocable to us in anyreasonable manner determined by our general partner in its 

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discretion.There is no cap on the amount that may be paid or reimbursed to our generalpartner for compensation or expenses incurred on our behalf. CRI currentlyprovides us with certain general and administration services. For a descriptionof these services, please read “Certain Relationships and Related PartyTransactions—Agreements with Harold Hamm and His Affiliates—Omnibus Agreement—Services.”In the omnibus agreement, CRI agreed to continue to provide these services tous for two years after our initial public offering, at the lower of CRI’s costto 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 resourcesand transitioned these services away from CRI. The remainder of general andadministration services provided by CRI under this agreement expired on February 15,2007.

***Long-Term IncentivePlan***

Our general partner hasadopted the Hiland Partners Long-Term Incentive Plan for employees anddirectors of our general partner and employees of its affiliates. The plan isintended to promote our interests and the interests of our general partner byproviding to employees and directors of our general partner and its affiliatesincentive 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 areessential for our growth and profitability and to encourage them to devotetheir best efforts to advancing our business. The long-term incentive plancurrently permits an aggregate of 680,000 common units to be issued withrespect to unit options, restricted units and phantom units granted under theplan. No more than 225,000 of the 680,000 common units may be issued withrespect to vested restricted or phantom units. The plan is administered by thecompensation committee of our general partner’s board of directors. The planwill continue in effect until the earliest of (i) the date determined bythe board of directors of our general partner; (ii) the date that commonunits are no longer available for payment of awards under the plan; or (iii) thetenth anniversary of the plan.

Our general partner’sboard of directors or compensation committee may, in their discretion,terminate, suspend or discontinue the long-term incentive plan at any time withrespect to any units for which a grant has not yet been made. Our generalpartner’s board of directors or its compensation committee also has the rightto alter or amend the long-term incentive plan or any part of the plan fromtime to time, including increasing the number of units that may be granted,subject to unitholder approval if required by the exchange upon which thecommon units are listed at that time. No change in any outstanding grant may bemade, however, that would materially impair the rights of the participantwithout the consent of the participant.

*Restricted Units andPhantom Units.*   A restricted unit is a commonunit that is subject to forfeiture. Upon vesting, the grantee receives a commonunit that is not subject to forfeiture. A phantom unit is a notional unit thatentitles the grantee to receive a common unit upon the vesting of the phantomunit or, in the discretion of the compensation committee, cash equivalent tothe value of a common unit. The compensation committee may make grants ofrestricted units and phantom units under the plan to employees and directorscontaining such terms as the compensation committee shall determine under theplan, including the period over which restricted units and phantom unitsgranted will vest. The committee may, in its discretion, base its determinationon the grantee’s period of service or upon the achievement of specifiedfinancial objectives. In addition, the restricted and phantom units will vestupon a change of control of us or our general partner, subject to additional orcontrary provisions in the award agreement.

If a grantee’s employmentor membership on the board of directors terminates for any reason, the grantee’srestricted units and phantom units will be automatically forfeited unless, andto the extent, the compensation committee provides otherwise or unlessotherwise provided in a written employment agreement between the grantee andour general partner or its affiliates. Common units to be delivered withrespect to these awards may be common units acquired by our general partner inthe open market, common units already owned by our general partner, commonunits acquired by our general partner directly from us or any other person orany combination of the foregoing. Our general partner will be 

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entitledto reimbursement by us for the cost incurred in acquiring common units. If weissue new common units with respect to these awards, the total number of commonunits outstanding will increase.

Distributions onrestricted units may be subject to the same vesting requirements as therestricted units, in the compensation committee’s discretion. The compensationcommittee, in its discretion, may also grant tandem distribution equivalentrights with respect to phantom units. These are rights that entitle the granteeto receive cash equal to the cash distributions made on the common units.

We intend for therestricted units and phantom units under the plan to serve as a means ofincentive compensation for performance and not primarily as an opportunity toparticipate in the equity appreciation of the common units. Therefore, planparticipants 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 planpermits the grant of options covering common units. The compensation committeemay make grants under the plan to employees and directors containing such termsas the committee shall determine. Except in the case of substitute optionsgranted to new employees or directors in connection with a merger,consolidation or acquisition, unit options may not have an exercise price thatis less than the fair market value of the units on the date of grant. Inaddition, unit options granted will generally become exercisable over a perioddetermined by the compensation committee and, in the compensation committee’sdiscretion, may provide for accelerated vesting upon the achievement ofspecified performance objectives. The unit options will become exercisable upona change in control of us or of our operating company. Unless otherwiseprovided in an award agreement, unit options may be exercised only by theparticipant during his lifetime or by the person to whom the participant’sright will pass by will or the laws of descent and distribution. If a grantee’semployment or membership on the board of directors terminates for any reason,the grantee’s unvested options will be automatically forfeited unless, and tothe extent, the compensation committee provides otherwise or unless otherwiseprovided in a written employment agreement or the option agreement between thegrantee and our general partner or its affiliates. If the exercise of an optionis to be settled in common units rather than cash, the general partner willacquire common units in the open market or directly from us or any other personor use common units already owned by our general partner or any combination ofthe foregoing. The general partner will be entitled to reimbursement by us forthe difference between the cost incurred by it in acquiring these common unitsand the proceeds it receives from a grantee at the time of exercise. Thus, thecost 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 totalnumber of common units outstanding will increase, and our general partner willpay us the proceeds it received from the grantee upon exercise of the unitoption. The plan has been designed to furnish additional compensation toemployees and directors and to align their economic interests with those ofcommon unitholders.

*Unit Option GrantAgreement.**  *Asof January 1, 2007, we have outstanding unit options to employees,officers and directors of our general partner to purchase an aggregate of128,468 common units with a weighted average exercise price of $28.24. Pleasesee the option grant table above for a description of grants made to namedexecutive officers during 2006 and 2005. Under the unit option grantagreements, the options vest and may be exercised in one third increments onthe anniversary of the grant date over a period of three years. In addition,the unit options will vest and become exercisable, subject to certainconditions, upon the occurrence of any of the following

·       the grantee becomesdisabled;

·       the grantee dies;

·       the grantee’s employment isterminated other than for cause; and

·       upon a change of control ofthe Partnership. .

In February 2006, onethird of the 143,000 unit options granted on February 10, 2005 vested. Ofthe 47,666 that vested, 39,633 were exercised in February 2006, resultingin cash contributions to us of $0.9 

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million.Additionally, 41,000 of the unit options granted on February 10, 2005vested on February 10, 2007 and 4,333 of the unit options granted in 2006vested on January 5, 2007. Of the total 45,333 that vested, 39,930 wereexercised in February 2007, resulting in cash contributions to us of $1.0million.

***Retention Agreementwith Randy Moeder***

In connection with RandyMoeder’s resignation, Mr. Moeder, the general partner of Hiland Partners,LP, the general partner of Hiland Holdings GP, LP and certain other partiesentered into a Retention Agreement. Under the agreement, if Mr. Moedercontinues his employment until the earlier to occur of September 1 2007,the date Mr. Moeder’s employment is terminated for any reason and amutually agreeable date, a portion of his 10,666 unvested options to purchasecommon units of Hiland Partners, LP and a portion of his 72,249 unvested Class BUnits in Hiland Holdings GP, LP will vest upon his termination of employment. Theportion of his unvested options and Class B Units that will vest will beequal to the number of days in the period beginning on February 10, 2007,in the case of the options, and February 15, 2007, in the case of theClass B Units, and ending on the date on which his employment isterminated. Mr. Moeder will forfeit the right to receive any remainingunvested options and Class B Units on such date.

***Report of theCompensation Committee***

The compensation committeeof the Board of Directors of Hiland Partners GP, LLC administers the executivecompensation program of Hiland Partners, LP. The compensation committee isprimarily responsible for reviewing, approving and reporting to the Board ofDirectors of Hiland Partners GP, LLC on major compensation and benefits plans,policies and programs of Hiland Partners, LP; reviewing and evaluating theperformance and approving the compensation of senior executive officers; andoverseeing management development programs, performance assessment of seniorexecutives and succession planning. Other specific duties and responsibilitiesinclude: annually reviewing and approving corporate goals and objectivesrelevant to the CEO base compensation, incentive-compensation plans andequity-based plans; evaluating the CEO’s performance in light of those goalsand objectives, and recommending to the Board of Directors, either as acommittee or together with the other independent directors, the CEO’scompensation levels based on this evaluation; and producing the required annualreport on executive compensation. The compensation committee annually evaluatesthe effectiveness of the executive compensation program in meeting itsobjectives.

As required by applicableregulations of the Securities and Exchange Commission, the compensationcommittee reviewed and discussed with management the compensation discussionand analysis contained in this Annual Report on Form 10-K. Based onthe reviews and discussions referred to above, the compensation committeerecommended to the Board of Directors of Hiland Partners GP, LLC that thecompensation discussion and analysis be included in the Annual Report on Form 10-Kfor the year ended December 31, 2006 for filing with the SEC.

Respectively submitted onMarch 13, 2007 by the members of the compensation committee of the Boardof Directors of Hiland Partners GP, LLC:

Harold Hamm, ChairmanJohn T. McNabb, IIRayford T. ReidEdward D. Doherty*Michael L. Greenwood*

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*—From May 2005 to August 2006, Edward D.Doherty was Chairman of the committee and Michael L. Greenwood was a member ofthe committee.

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**Item 12.**                 SecurityOwnership of Certain Beneficial Owners and Management and Related UnitholderMatters

*Beneficial Ownership OfHiland Partners, LP.**  *Thefollowing table sets forth the beneficial ownership of our units as of March 5,2007 held by each person who beneficially owned more than 5% or more of thethen outstanding units and all of the directors, named executive officers, anddirectors and executive officers as a group of our general partner.

| ** **                                       | ** ** | ** **            | ** ** | ** **             | ** ** | ** **       | ** ** | **Percentage of** | ** ** | ** **             | ** ** |
|--------------------------------------------------|------------|-----------------------|------------|------------------------|------------|------------------|------------|------------------------|------------|------------------------|------------|
| ** **                                       | ** ** | ** **            | ** ** | **Percentage of** | ** ** | **Subordinated** | ** ** | **Subordinated**       | ** ** | **Percentage of** | ** ** |
| ** **                                       | ** ** | **Common Units** | ** ** | **Common Units**  | ** ** | **Units**        | ** ** | **Units**              | ** ** | **Total Units**   | ** ** |
| ** **                                       | ** ** | **Beneficially**      | ** ** | **Beneficially**       | ** ** | **Beneficially** | ** ** | **Beneficially**       | ** ** | **Beneficially**       | ** ** |
| **Name of Beneficial Owner**      | ** ** | ** **            | ** ** | **Owned**              | ** ** | **Owned**        | ** ** | **Owned**              | ** ** | **Owned**              | ** ** | **Owned** | ** ** |
| Harold Hamm(1)(2)(3)                             |       |                  | 1,301,471  |                   |       |             | 24.9       | %                      |       |                   | 4,080,000  |   |   |   | 100.0 | % |   |   | 57.8 | % |   |
| Randy Moeder(1)(2)                               |       |                  | 10,667     |                   |       |             | —     |                   |       |                   | —     |   |   |   | — |   |   |   | — |   |   |
| Ken Maples(1)(2)(4)                              |       |                  | 6,667      |                   |       |             | —     |                   |       |                   | —     |   |   |   | — |   |   |   | — |   |   |
| Robert Shain(1)(5)                               |       |                  | 8,000      |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| Ron Hill(1)                                      |       |                  | —     |                   |       |             | —     |                   |       |                   | —     |   |   |   | — |   |   |   | — |   |   |
| Clint Duty(1)(8)                                 |       |                  | —     |                   |       |             | —     |                   |       |                   | —     |   |   |   | — |   |   |   | — |   |   |
| Michael L. Greenwood(1)(2)(6)                    |       |                  | 11,291     |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| Edward D. Doherty(1)(2)(6)                       |       |                  | 3,000      |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| Rayford T. Reid(1)(2)(6)                         |       |                  | 15,818     |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| Shelby E. Odell(1)(2)(6)                         |       |                  | 3,000      |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| John T. McNabb, II(1)(7)                    |       |                  | 2,000      |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| Dr. David L. Boren(1)(7)                    |       |                  | 2,000      |                   |       |             | *          |                   |       |                   | —     |   |   |   | — |   |   |   | * |   |   |
| Kayne Anderson Capital Advisors, L.P.(9)         |       |                  | 377,292    |                   |       |             | 7.2        | %                      |       |                   | —     |   |   |   | — |   |   |   | 4.1 | % |   |
| Fiduciary Asset Management, LLC.(10)             |       |                  | 384,980    |                   |       |             | 7.4        | %                      |       |                   | —     |   |   |   | — |   |   |   | 4.1 | % |   |
| All directors and  executive officers as a group |       |                  | 1,363,914  |                   |       |             | 26.1       | %                      |       |                   | 4,080,000  |   |   |   | 100.0 | % |   |   | 58.5 | % |   |
|                                                  |            |                       |            |                        |            |                  |            |                        |            |                        |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

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*                  *** *Lessthan 1%.

             (1)  The address of this person is 205 West Maple, Suite 1100,Enid, Oklahoma 73701.

             (2)  These individuals each hold an ownership interest inHiland Holdings GP, LP as indicated in the following table.

             (3)  Mr. Hamm indirectly owns 94% of Hiland Partners GPHoldings, LLC, the general partner of Hiland Holdings GP, LP. Accordingly, Mr. Hammis deemed to be the beneficial owner of the 1,301,471 common units and4,080,000 subordinated units held by Hiland Holdings GP, LP.

             (4)  These**unitsunderly unit options and are deemed to be outstanding pursuant to Rule 13d-3.

             (5)  3,000 of the indicated common units are restrictedunits that vest on the anniversary of the grant date over a period of fouryears and 5,000 of these units underly unit options and are deemed to beoutstanding pursuant to Rule 13d-3.

             (6)  1,500 of the indicated common units are restricted unitsthat vest on the anniversary of the grant date over a period of three years and1,000 of the indicated common units are restricted units that vest on theanniversary of the grant date over a period of four years.

             (7)  2,000 of the indicated common units are restrictedunits that vest on the anniversary of the grant date over a period of fouryears.

             (8)  The address of this person is 13779 E. 51st Street, Apt3206, Tulsa, Oklahoma 74134.

             (9)  The address of this person is 1800 Avenue of the Stars,Second Floor, Los Angeles, CA 90067.

        (10)  The address of this person is 8112 Maryland Avenue, Suite 400,St. Louis, MO 63105.

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*Beneficial Ownership of Hiland Holdings GP, LP.* The followingtable sets forth the beneficial ownership of units of Hiland Holdings GP, LP asof March 5, 2007 held by each person who beneficially owned more than 5%or more of the then outstanding units and all of the directors, named executiveofficers, and directors and executive officers as a group of Hiland HoldingsGP, LP.

| ** **                                       | ** ** | ** **            | ** ** | **Percentage of** | ** ** |
|--------------------------------------------------|------------|-----------------------|------------|------------------------|------------|
| ** **                                       | ** ** | **Common Units** | ** ** | **Common Units**  | ** ** |
| ** **                                       | ** ** | **Beneficially**      | ** ** | **Beneficially**       | ** ** |
| **Name of Beneficial Owner(1)**   | ** ** | ** **            | ** ** | **Owned**              | ** ** | **Owned** | ** ** |
| Harold Hamm(2)                                   |       |                  | 7,657,870  |                   |       |   | 35.4 | % |   |
| Harold Hamm DST  Trust(2)                        |       |                  | 3,205,120  |                   |       |   | 14.8 | % |   |
| Harold Hamm HJ  Trust(2)                         |       |                  | 2,136,533  |                   |       |   | 9.9 | % |   |
| Randy Moeder(3)                                  |       |                  | 388,890    |                   |       |   | 1.8 | % |   |
| Ken Maples(4)                                    |       |                  | 161,587    |                   |       |   | * |   |   |
| Michael L.  Greenwood(5)                         |       |                  | 2,000      |                   |       |   | * |   |   |
| Edward D. Doherty(5)                             |       |                  | 2,500      |                   |       |   | * |   |   |
| Rayford T. Reid(5)                               |       |                  | 27,000     |                   |       |   | * |   |   |
| Shelby E. Odell(5)                               |       |                  | 7,000      |                   |       |   | * |   |   |
| Dr. Cheryl  L. Evans(5)                     |       |                  | 2,500      |                   |       |   | * |   |   |
| Dr. Bobby B.  Lyle(5)                       |       |                  | 27,000     |                   |       |   | * |   |   |
| All directors and  executive officers as a group |       |                  | 8,276,347  |                   |       |   | 38.3 | % |   |
|                                                  |            |                       |            |                        |            |  |  |  |  |  |  |

 

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**                   *Less than 1%.

(1)          The address of eachperson listed above is 205 West Maple, Suite 1100, Enid, Oklahoma 73701,except for the Harold Hamm DST Trust and the Harold Hamm HJ Trust, which Mr. BertMackie is the trustee for both trusts and his address is c/o Security NationalBank, 201 West Broadway, Enid, Oklahoma 73702-1272.

(2)          Harold Hamm, the HaroldHamm DST Trust and the Harold Hamm HJ Trust have a 90.7%, 5.6% and a 3.7%ownership interest, respectively, in Continental Gas Holdings, Inc., whichbeneficially owns 8,443,076 common units. The units held by Continental GasHoldings, Inc. are reported in this table as beneficially owned by Mr. Hamm,the Harold Hamm DST Trust and the Harold Hamm HJ Trust in proportion to theirrespective ownership interest in Continental Gas Holdings, Inc. Theaddress of Continental Gas Holdings, Inc. is 205 West Maple, Suite 1100,Enid, Oklahoma 73701.

(3)          These reported numbersinclude 144,498 Class B common units, of which 72,249 Class B commonunits are unvested. On February 19, 2007, Mr. Moeder elected toconvert the 72,249 vested Class B units to common units. See “RetentionAgreement with Randy Moeder”.

(4)          These reported numbersinclude 87,552 Class B common units, of which 43,766 Class B commonunits are unvested.

(5)          2,000 of the indicatedcommon units are restricted units that vest on the anniversary of the grantdate over a period of four years.

The Class B common units were issued to Messrs. Moederand Maples as consideration for their unvested ownership interests in HilandPartners GP, LLC. The Class B common units will have substantiallyidentical rights as the common units and, upon vesting, will become convertibleat the election of the holder into common units. Prior to conversion, Messrs. Moederand Maples will not be entitled to transfer the Class B common units. The Class Bcommon units will vest in equal increments on February 15, 2008. In addition,any unvested Class B common units will become fully vested upon thedisability, death or termination other than for cause of the holder or a changeof control of our general partner. If either Mr. Moeder or Mr. Maplesceases to be an officer or employee of our general partner for 

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any other reason, hisunvested Class B common units will be forfeited and transferred to theContributing Parties on a pro rata basis based on their vested ownership ofHiland Partners GP, LLC immediately prior to the contribution of thoseinterests to us in connection with our formation. See “Retention Agreement withRandy Moeder”.

*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, 1,301,471of our common units and 4,080,000 of our subordinated units.

**Item 13.**                 CertainRelationships and Related Transactions

HaroldHamm, the Harold Hamm DST Trust and the Harold Hamm HJ Trust own 60.1%of Hiland Holdings GP, LP, who owns all of our 2% general partner interest, allof our incentive distributions rights, 1,301,471 of our common units and4,080,000 of our subordinated units.

**Distributions andPayments to Our General Partner and its Affiliates**

Our general partner andits affiliates do not receive any management fee or other compensation for themanagement of our business and affairs, but they are reimbursed for allexpenses that they incur on our behalf, including general and administrativeexpenses, salaries and benefits for all of our employees and other corporateoverhead. Our general partner determines the amount of these expenses. In theomnibus agreement, CRI agreed to continue to provide certain general andadministrative services to us for two years after our initial public offering,at the lower of CRI’s cost to provide the services or $50,000 per year. Duringthe third quarter of 2006, we hired a director of information technology and adirector of human resources and transitioned these services away from CRI. Theremainder of general and administration services provided by CRI under thisagreement expired on February 15, 2007. Please read “—Omnibus Agreement—Services”below. In addition, our general partner owns the 2% general partner interestand all of the incentive distribution rights. Our general partner is entitledto receive incentive distributions if the amount we distribute with respect toany quarter exceeds levels specified in our partnership agreement.

**CompensationCommittee Interlocks and Insider Participation**

Harold Hamm serves as thechairman of our Compensation Committee. Mr. Hamm controls CRI, and therequired disclosure concerning related party transactions involving Mr. Hamm,CRI and us are set forth below.

**Omnibus Agreement**

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

·       Harold Hamm’s agreement notto compete and to cause his affiliates (including CRI) not to compete with usunder certain circumstances;

·       an indemnity by CRI, HilandPartners, LLC and Continental Gas Holdings, Inc. for prior tax liabilitiesresulting from the assets contributed to the partnership;

·       an indemnity by CRI forliabilities associated with oil and gas properties conveyed by CGI to CRI bydividend; and

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

·       for a two-year period, CRIwill provide certain general and administrative services;

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***Non-Competition***

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

·       any business that isprimarily related to the exploration for and production of oil or natural gas,including the sale and marketing of oil and natural gas derived from suchexploration and production activities;

·       the purchase and ownershipof not more than five percent of any class of securities of any entity engagedin the business described above;

·       any business conducted byHarold Hamm or his affiliates as of the date of the omnibus agreement;

·       any business that HaroldHamm or his affiliates acquires or constructs that has a fair market value orconstruction cost, as applicable, of less than $5.0 million;

·       any business that HaroldHamm or his affiliates acquires or constructs that has a fair market value orconstruction cost, as applicable, of $5.0 million or more if we have beenoffered the opportunity to purchase the business for the fair market value orconstruction cost, as applicable, and we decline to do so with the concurrenceof the conflicts committee of our general partner; and

·       any business conducted byHarold Hamm or his affiliates, with the approval of the conflicts committee.

Thesenon-competition obligations will terminate on the first to occur of thefollowing events:

·       the first day on which theHamm Parties no longer control us;

·       the death of Harold Hamm;and

·       February 15, 2010, thefifth anniversary of the closing of our initial public offering.

***Indemnification***

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

***Option to Purchase the Bakken Gathering System***

The omnibus agreement alsocontained the terms under which we held an option to purchase the Bakkengathering system from Hiland Partners, LLC. Pursuant to the acquisitionagreement described below, the omnibus agreement was amended to provide for thepurchase of the membership interests in Hiland Partners, LLC instead of theBakken gathering system, and in September 2005 we purchased all of theoutstanding membership interests in Hiland Partners, LLC.

**AcquisitionAgreement**

On September 9, 2005,we, through our operating company, entered into an acquisition agreement withHiland Partners, LLC and its members pursuant to which we acquired theoutstanding membership interests in Hiland Partners, LLC for approximately$92.7 million in cash, consisting of a cash payment of 

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approximately$57.7 million to the former members of Hiland Partners, LLC and therepayment of approximately $35.0 million of bank indebtedness of HilandPartners, LLC. The acquisition closed on September 26, 2005 and had aneffective date of September 1, 2005. The membership interests in HilandPartners, LLC acquired by us were owned 49% by Harold Hamm, 49% by the HammTrusts, and 2% by Equity Financial Services, Inc., whose sole shareholder,director and executive officer is Randy Moeder. Accordingly, Mr. Hamm, theHamm Trusts and Equity Financial Services, Inc. received approximately$28.3 million, $28.3 million and $1.2 million, respectively, inconnection with the transaction, subject to certain closing adjustments. Amutually-agreed-upon investment banking firm determined the fair market valueof the Bakken gathering system, the principal asset of Hiland Partners, LLC,and the conflicts committee of the board of directors of our general partner,consisting of its independent directors, approved the transaction.

***Services***

CRI agreed to providetechnology support and human resource functions to us for two years, at thelower of CRI’s cost to provide the services or $50,000 per year. During thethird quarter of 2006, we hired a director of information technology and adirector of human resources and transitioned these services away from CRI.

**Contracts with CRI**

***CompressionServices Agreement***

Prior to our initialpublic offering, Hiland Partners, LLC leased certain compression assets(which were contributed to us in connection with our initial public offering)to CRI. Hiland Partners, LLC received $3.9 million and $3.3 millionfor the years ended December 31, 2004 and 2003, respectively under thisarrangement. In connection with our initial public offering, we entered into afour-year compression services agreement with CRI as described under “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—OurContracts—Compression Services Agreement.” For the years ended December 31,2006 and 2005, we received revenues of $4.8 million and $4.2 million,respectively from CRI under this arrangement.

***Gas PurchaseContracts***

We purchase natural gasand NGLs from CRI and its affiliates. We purchased natural gas and NGLs fromCRI and its affiliates in the amount of approximately $50.3 million,$45.8 million and $27.6 million for the years ended December 31,2006, 2005 and 2004, respectively.

***Badlands PurchaseContract***

On November 8, 2005,we entered into a new 15-year definitive gas purchase agreement with CRIunder which we will gather, treat and process additional natural gas, which isproduced as a by-product of CRI’s secondary oil recovery operations, in theareas specified by the contract. In return, we will receive 50% of the proceedsattributable to residue gas and natural gas liquids sales as well as certainfixed 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 ofdirectors, as well as the conflicts committee of the board of directors, of ourgeneral partner have approved the agreement.

In order to fulfill ourobligations under the agreement, we are in the process of expanding ourBadlands gas gathering system and processing plant located in Bowman County,North Dakota. This expansion project will include the construction of a 40,000Mcf/d nitrogen rejection plant, which is expected to be operational in thesecond quarter of 2007, and the expansion of our existing Badlandsfield-gathering infrastructure. We intend to invest approximately$40.0 million in the expansion project by the first quarter of 2007, ofwhich approximately $31.7 million had been invested as of December 31,2006. We expect to invest an additional $9.5 million on this project laterin 2007 to expand the system.

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***Other Agreements***

Historically, our predecessor and Hiland Partners, LLChave contracted for down hole well services, fluid supply and oil fieldservices from businesses in which Harold Hamm and members of his family have historicallyowned equity interests. Mr. Hamm and members of his family sold thesebusinesses to Complete Production Services, Inc. in October 2004. Mr. Hammis currently a director and stockholder of Complete Production Services.Payments made for these services by our predecessor and Hiland Partners, LLC ona combined basis were $219,000 and $257,000 during the years ended December 31,2006 and 2005, respectively. We have continued to obtain services from thesecompanies following the completion of our initial public offering. Based onvarious bids received by our general partner from unaffiliated third parties,our general partner believes that amounts paid for these services arecomparable to amounts which would be charged by an unaffiliated third party.

In addition, Hiland Partners, LLC compensated EquityFinancial Services, Inc., an entity wholly owned by our President, RandyMoeder, for management and administrative services. Total payments to EquityFinancial Services were approximately $11,000 and $65,000 during the yearsended December 31, 2005 and 2004, respectively. Following completion ofour initial public offering, this service arrangement was terminated.

We lease office space under operating leases from anentity wholly owned by Harold Hamm. Rents paid under these leases totaledapproximately $118,000, $51,000 and $47,000 for the years ended December 31,2006, 2005 and 2004 respectively. These rates are consistent with the ratescharged to other non-affiliated tenants in the building which we office.

In connection with thecompletion of our initial public offering, we adopted an ethics policy thatrequires related party transactions be reviewed to ensure that they are fairand reasonable to us. This requirement is also contained in our partnershipagreement.

**Item 14.**                 PrincipalAccountant Fees and Services

Our audit committee hasadopted an audit committee charter, which is available on our Web site atwww.hilandpartners.com. The charter requires our audit committee to approve inadvance all audit and non-audit services to be provided by our independentregistered public accounting firm. Our audit committee ratified Grant ThorntonLLP, Independent Registered Public Accounting Firm, to audit the books, recordsand accounts of Hiland Partners, LP for the year ended December 31, 2006. Auditfees paid to Grant Thornton LLP in 2006 include payments for our annual audit,review of documents filed with the Securities and Exchange Commission, SarbanesOxley Section 404 attest services and review of our quarterly reports on Form 10-Q.Fees for audit related services relate to consultation regarding an acquisitionand internal control review. Tax fees include tax compliance, tax planning andacquisition matters. Fees paid in 2005 to Grant Thornton LLP for audit servicesincluded fees associated with the annual audit, regulatory filings required inour initial and secondary public offerings, preparation for Sarbanes-Oxley Section 404attest services and reviews of our quarterly reports on Form 10-Q. Additionalfees paid to Grant Thornton LLP for audit-related services consisted ofconsultation regarding an acquisition and for tax, which consisted ofcompliance and advisory services. Fees paid to Grant Thornton LLP for theperiods indicated are as follows:

| ** **         | ** ** | **2006** | ** ** | **2005** | ** ** |
|--------------------|------------|----------|------------|----------|------------|
| Audit Fees         |       | $        | 338,000    |     | $          | 328,000 |   |
| Audit Related Fees |       | 8,000    |       | 1,000    |       |
| Tax Fees           |       | 165,000  |       | 173,000  |       |
| All Other Fees     |       | —   |       | —   |       |
| Total              |       | $        | 511,000    |     | $          | 502,000 |   |

 

95

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**PART IV**

**Item 15.**                 Exhibitsand Financial Statement Schedules

(a)           Financial Statements

The financialstatements listed in the accompanying Index to Consolidated FinancialStatements are filed as part of this Annual Report on Form 10-K.

(b)          Other Information

None.

**EXHIBITS**

| Exhibit    | ** ** | ** **                                                                                                                                                                                                                                                                     |
|------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| **Number** | ** ** | ** **                                                                                                                                                                                                                                                                     | ** ** | **Description** |
| 2.1        | —     | Acquisition Agreement by and among Hiland Operating,  LLC and Hiland Partners, LLC dated as of September 1, 2005 (incorporated  by referenced to Exhibit 2.1 of Registrant’s Form 8-K filed  September 29, 2005)                                      |
| 3.1        | —     | Certificate of Limited  Partnership of Hiland Partners, LP. (incorporated by 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))                                                 |
|            |            |                                                                                                                                                                                                                                                                                |  |  |

96

----

 

| †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 10.10 of Registrant’s annual report on Form 10-K filed on  March 30, 2005)                                                                                                                                                                                                                         |
| 10.11*     | — | Director’s Compensation  Summary (incorporated by reference to exhibit 10.11 of Registrant’s annual  report on Form 10-K filed on March 30, 2005)                                                                                                                                                                                                                                                                                                                                                                                                                      |
| 10.12*     | — | Form of Restricted  Unit Grant Agreement (incorporated by reference to exhibit 10.1 of  Registrant’s Form 8-K filed on November 14, 2005)                                                                                                                                                                                                                                                                                                                                                                                                                              |
| 10.13      | — | First Amendment, dated  as of September 26, 2005 to Credit Agreement dated as of  February 15, 2005 among Hiland Operating, LLC and the lenders thereto  (incorporated by reference to exhibit 10.1 of Registrant’s Form 8-K  filed on September 29, 2005)                                                                                                                                                                                                                                                                                                        |
| 10.14      | — | Gas Purchase Agreement  among Hiland Partners, LP and Continental Resources, Inc. dated  November 8, 2005 (incorporated by reference to exhibit 10.1 of Registrant’s  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 Registrant’s 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 Registrant’s 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 Registrant’s 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 Registrant’s 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)                                                                                                                                                                                                                                                                      |
| 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)                                                                                                                                                                                                                                                                                                                                                                               |

97

----

 

| 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                                                                          |

 

----

†                    Portions ofthis exhibit have been omitted pursuant to a request for confidentialtreatment.

*                    Constitutesmanagement contracts or compensatory plans or arrangements.

98

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized in the city of Enid,Oklahoma, on the 16th day of March, 2007.

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

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant in thecapacities indicated on the 16th day of March, 2007.

|                             | **Signature** | ** **                                             | ** ** | ** ** | **Title** | ** ** |
|-----------------------------|---------------|--------------------------------------------------------|------------|------------|-----------|------------|
| /s/ HAROLD  HAMM            |          | Chairman of the Board                                  |
| Harold Hamm                 |          |                                                   |
| /s/ RANDY MOEDER            |          | Chief Executive  Officer, President and Director       |
| Randy Moeder                |          |                                                   |
| /s/ KEN MAPLES              |          | Chief Financial  Officer, Vice President—Finance, |
| Ken Maples                  |          | Secretary and Director                                 |
| /s/ MICHAEL L. GREENWOOD    |          | Director                                               |
| Michael L. Greenwood        |          |                                                   |
| /s/ EDWARD D. DOHERTY       |          | Director                                               |
| Edward D. Doherty           |          |                                                   |
| /s/ RAYFORD T. REID         |          | Director                                               |
| Rayford T. Reid             |          |                                                   |
| /s/ SHELBY E. ODELL         |          | Director                                               |
| Shelby E. Odell             |          |                                                   |
| /s/ JOHN T. MCNABB, II |          | Director                                               |
| John T. McNabb, II     |          |                                                   |
| /s/ DR. DAVID L. BOREN |          | Director                                               |
| Dr. David L. Boren     |          |                                                   |

 

99

----

**INDEXTO 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,  2006 and 2005                                                                                 |   | F-6    |
| Consolidated Statements of Operations for the years  ended December 31, 2006, 2005 and 2004                                                   |   | F-7    |
| Consolidated  Statements of Cash Flows for the years ended December 31, 2006, 2005 and  2004                                                  |   | F-8    |
| Consolidated Statement of Changes in Owner’s Equity  and Comprehensive Income for the years ended December 31, 2006,  2005 and 2004 |   | F-10   |
| Notes  to Consolidated Financial Statements                                                                                                        |   | F-11   |

 

F-1

----

**Management’s Reporton Internal Control Over Financial Reporting**

The management of Hiland Partners, LP (the “Partnership”)is responsible for establishing and maintaining an adequate internal controlover financial reporting. Internal control over financial reporting is aprocess designed to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for externalreporting purposes in accordance with accounting principles generally acceptedin the United States of America. Because of its inherent limitations, internalcontrol over financial reporting may not prevent or detect misstatements. Withthe participation of the Chief Executive Officer and the Chief FinancialOfficer, our management has assessed the effectiveness of the Partnership’sinternal control over financial reporting as of December 31, 2006. Inmaking its assessment, management has utilized the criteria set forth by theCommittee of Sponsoring Organizations (COSO) of the Treadway Commission in *Internal Control—Integrated Framework.* Management concludedthat, based on its assessment, the Partnership’s internal control overfinancial reporting was effective as of December 31, 2006.

HilandPartners, LP management’s assessment of the effectiveness of the Partnership’sinternal control over financial reporting as of December 31, 2006 has beenaudited by Grant Thornton, LLP, an independent registered public accountingfirm, as stated in their report included herein.
| /s/ RANDY MOEDER          |     |
|---------------------------|----------|
| *Chief Executive Officer* |
| /s/ KEN MAPLES            |     |
| *Chief Financial Officer* | * * |

 

F-2

----

**Report ofIndependent Registered Public Accounting Firm**

Boardof Directors

Hiland Partners GP, LLC

We have audited management’s assessment, included inthe accompanying Management’s Report on Internal Control Over FinancialReporting, that Hiland Partners, LP and subsidiaries (the Partnership)maintained effective internal control over financial reporting as of December 31,2006, based on criteria established in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).  The Partnership’s management is responsiblefor maintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting. Ourresponsibility is to express an opinion on management’s assessment and anopinion on the effectiveness of the Partnership’s internal control overfinancial reporting based on our audit.

We conducted our audit in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting wasmaintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the design and operatingeffectiveness of internal control, and performing such other procedures as weconsidered necessary in the circumstances. We believe that our audit provides areasonable basis for our opinions.

A company’s internal control over financial reportingis a process designed to provide reasonable assurance regarding the reliabilityof financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies andprocedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being madeonly in accordance with authorizations of management and directors of thecompany; and (3) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

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

In our opinion, management’s assessment that thePartnership maintained effective internal control over financial reporting asof December 31, 2006, is fairly stated, in all material respects, based oncriteria established in *Internal Control—IntegratedFramework* issued by COSO. Also in our opinion, the Partnershipmaintained, in all material respects, effective internal control over financialreporting as of December 31, 2006, based on *Internal Control—Integrated Framework* issued by COSO.

F-3

----

Wealso have audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the consolidated balance sheets ofthe Partnership as of December 31, 2006 and 2005, and the relatedconsolidated statements of operations, cash flows, and changes in owners’equity and comprehensive income for each of the three years in the period endedDecember 31, 2006 and our report dated March 13, 2007 expressed anunqualified opinion on those financial statements.
| /s/ GRANT THORNTON  LLP |   |
|-------------------------|--------|
| Oklahoma City, Oklahoma |
| March 13, 2007     |

 

F-4

----

**Report ofIndependent Registered Public Accounting Firm**

Board of DirectorsHiland Partners GP, LLC

We have audited the accompanying consolidated balancesheets of Hiland Partners, LP and subsidiaries (the Partnership) as of December 31,2006 and 2005, and the related consolidated statements of operations, cashflows, and changes in owner’s equity and comprehensive income for each of thethree years in the period ended December 31, 2006. These financialstatements are the responsibility of the Partnership’s management. Our responsibilityis to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit includes examining, on a test basis, evidence supportingthe amounts and disclosures in the financial statements. An audit also includesassessing the accounting principles used and significant estimates made bymanagement, 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 statementsreferred to above present fairly, in all material respects, the financialposition of Hiland Partners, LP and subsidiaries as of December 31, 2006and 2005, and the results of their operations and their cash flows for each ofthe three years in the period ended December 31, 2006 in conformity withaccounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financialstatements, the Partnership adopted Statement of Financial Accounting StandardsNo. 123 (revised 2004), *Share-Based Payment,*ona modified prospective basis as of January 1, 2006.

Wealso have audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), the effectiveness of thePartnership’s internal control over financial reporting as of December 31,2006, based on criteria established in *Internal Control—IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO) and our report dated March 13, 2007 expressedan unqualified opinion on the effectiveness of the Partnership’s internalcontrol over financial reporting and on management’s assessment thereof.
| /s/ GRANT  THORNTON LLP |   |
|-------------------------|--------|
| Oklahoma City, Oklahoma |
| March 13, 2007     |

 

F-5

----

**HILAND PARTNERS, LP** Consolidated Balance Sheets

| ** **                                                                                                                                     | ** ** | **December 31,**                                       | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                     | ** ** | **2006**                                                    | ** ** | **2005**              | ** ** |
| ** **                                                                                                                                     | ** ** | **(in thousands, except unit amounts)** | ** ** |
| **ASSETS**                                                                                                                                     | ** ** |                                                        | ** ** | ** **            |       |   | ** ** | ** ** |   |
| **Current assets:**                                                                                                                            | ** ** |                                                        | ** ** | ** **            |       |   | ** ** | ** ** |   |
| Cash and cash  equivalents                                                                                                                     |       |                                                        | $          | 10,386                | ** ** |   |   | $ | 6,187 |   |   |
| Accounts receivable:                                                                                                                           |       |                                                        |       | ** **            |       |   |   |   |   |
| Trade                                                                                                                                          |       |                                                        | 23,702     | ** **            |       |   | 21,893 |   |   |
| Affiliates                                                                                                                                     |       |                                                        | 1,284      | ** **            |       |   | 1,523 |   |   |
|                                                                                                                                           |       |                                                        | 24,986     | ** **            |       |   | 23,416 |   |   |
| Fair value of  derivative assets                                                                                                               |       |                                                        | 4,707      | ** **            |       |   | 868 |   |   |
| Other current  assets                                                                                                                          |       |                                                        | 725        | ** **            |       |   | 395 |   |   |
| Total current  assets                                                                                                                          |       |                                                        | 40,804     | ** **            |       |   | 30,866 |   |   |
| Property and equipment, net                                                                                                                    |       |                                                        | 252,801    | ** **            |       |   | 120,715 |   |   |
| Intangibles, net                                                                                                                               |       |                                                        | 46,561     | ** **            |       |   | 41,179 |   |   |
| Fair value of  derivative assets                                                                                                               |       |                                                        | 1,955      | ** **            |       |   | 181 |   |   |
| Other assets, net                                                                                                                              |       |                                                        | 1,695      | ** **            |       |   | 1,028 |   |   |
| **Total assets**                                                                                                                               |       |                                                        | $          | 343,816               | ** ** |   |   | $ | 193,969 |   |   |
| **LIABILITIES AND OWNERS’ EQUITY**                                                                                                        | ** ** |                                                        | ** ** | ** **            |       |   | ** ** | ** ** |   |
| **Current liabilities:**                                                                                                                       | ** ** |                                                        | ** ** | ** **            |       |   | ** ** | ** ** |   |
| Accounts payable                                                                                                                               |       |                                                        | $          | 19,032                | ** ** |   |   | $ | 13,324 |   |   |
| Accounts payable—affiliates                                                                                                               |       |                                                        | 4,412      | ** **            |       |   | 6,122 |   |   |
| Fair value of  derivative liabilities                                                                                                          |       |                                                        | 1,902      | ** **            |       |   | — |   |   |
| Accrued  liabilities                                                                                                                           |       |                                                        | 1,173      | ** **            |       |   | 1,126 |   |   |
| Total current  liabilities                                                                                                                     |       |                                                        | 26,519     | ** **            |       |   | 20,572 |   |   |
| Commitments and  contingencies (Note 7)                                                                                                        |       |                                                        |       | ** **            |       |   |   |   |   |
| Long-term debt                                                                                                                                 |       |                                                        | 147,064    | ** **            |       |   | 33,784 |   |   |
| Fair value of  derivative liabilities                                                                                                          |       |                                                        | 291        | ** **            |       |   | — |   |   |
| Asset retirement  obligation                                                                                                                   |       |                                                        | 2,196      | ** **            |       |   | 1,024 |   |   |
| **Owners’  equity**                                                                                                                       | ** ** |                                                        | ** ** | ** **            |       |   | ** ** | ** ** |   |
| Limited partners’  interest:                                                                                                              |       |                                                        |       | ** **            |       |   |   |   |   |
| Common unitholders (5,166,413 and 4,350,000 units  issued and outstanding at December 31, 2006 and December 31, 2005,  respectively) |       |                                                        | 139,781    | ** **            |       |   | 110,027 |   |   |
| Subordinated unitholders (4,080,000 units issued and  outstanding)                                                                             |       |                                                        | 19,913     | ** **            |       |   | 25,126 |   |   |
| General partner  interest                                                                                                                      |       |                                                        | 3,696      | ** **            |       |   | 2,676 |   |   |
| Unearned  compensation                                                                                                                         |       |                                                        | —     | ** **            |       |   | (289 | ) |   |
| Accumulated other  comprehensive income                                                                                                        |       |                                                        | 4,356      | ** **            |       |   | 1,049 |   |   |
| **Total  owners’ equity**                                                                                                                 |       |                                                        | 167,746    | ** **            |       |   | 138,589 |   |   |
| **Total  liabilities and owners’ equity**                                                                                                 |       |                                                        | $          | 343,816               | ** ** |   |   | $ | 193,969 |   |   |

 

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

F-6

----

**HILAND PARTNERS, LP** Consolidated Statements of Operations

| ** **                                                                           | ** ** | ** **                                                           | ** ** | ** **            | ** ** | **Predecessor**     | ** ** |
|--------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|-----------------------|------------|---------------------|------------|
| ** **                                                                           | ** ** | ** **                                                           | ** ** | ** **            | ** ** | **Year Ended** | ** ** |
| ** **                                                                           | ** ** | **Year Ended December 31,**                           | ** ** | **December 31,** | ** ** |
| ** **                                                                           | ** ** | **2006**                                                             | ** ** | **2005**              | ** ** | **2004**            | ** ** |
| ** **                                                                           | ** ** | **(In thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                                                        | ** ** | ** **                                                           | ** ** | ** **            | ** ** |                | ** ** | ** ** |   |
| Midstream operations                                                                 |       |                                                                 |       |                  |       |                |       |   |   |
| Third parties                                                                        |       | $                                                                    | 210,732    |                  | $          | 157,138             |       |   | $ | 95,019 |   |   |
| Affiliates                                                                           |       | 4,135                                                                |       | 5,246                 |       |                | 3,277      |   |   |
| Compression  services, affiliate                                                     |       | 4,819                                                                |       | 4,217                 |       |                | —     |   |   |
| Total revenues                                                                       |       | 219,686                                                              |       | 166,601               |       |                | 98,296     |   |   |
| **Operating  costs and expenses:**                                                   | ** ** | ** **                                                           | ** ** | ** **            | ** ** |                | ** ** | ** ** |   |
| Midstream  purchases (exclusive of items shown separately below)                     |       | 105,884                                                              |       | 87,247                |       |                | 54,962     |   |   |
| Midstream  purchases—affiliate (exclusive of items shown separately below) |       | 50,309                                                               |       | 45,842                |       |                | 27,570     |   |   |
| Operations and  maintenance                                                          |       | 16,071                                                               |       | 7,359                 |       |                | 4,933      |   |   |
| Depreciation,  amortization and accretion                                            |       | 22,130                                                               |       | 11,112                |       |                | 4,127      |   |   |
| Gain on sale of  assets                                                              |       | —                                                               |       | —                |       |                | (19        | ) |   |
| General and  administrative expenses                                                 |       | 4,994                                                                |       | 2,470                 |       |                | 1,082      |   |   |
| Total operating  costs and expenses                                                  |       | 199,388                                                              |       | 154,030               |       |                | 92,655     |   |   |
| Operating income                                                                     |       | 20,298                                                               |       | 12,571                |       |                | 5,641      |   |   |
| **Other  income (expense):**                                                         | ** ** | ** **                                                           | ** ** | ** **            | ** ** |                | ** ** | ** ** |   |
| Interest and  other income                                                           |       | 323                                                                  |       | 192                   |       |                | 40         |   |   |
| Amortization of  deferred loan costs                                                 |       | (407                                                                 | )          | (484                  | )          |                | (102       | ) |   |
| Interest expense                                                                     |       | (5,532                                                               | )          | (1,942                | )          |                | (702       | ) |   |
| Other income  (expense), net                                                         |       | (5,616                                                               | )          | (2,234                | )          |                | (764       | ) |   |
| **Income from continuing operations**                                                |       | 14,682                                                               |       | 10,337                |       |                | 4,877      |   |   |
| **Discontinued  operations, net**                                                    |       | —                                                               |       | —                |       |                | 35         |   |   |
| **Net  income**                                                                      |       | 14,682                                                               |       | 10,337                |       |                | $          | 4,912 |   |   |
| Less income attributable to predecessor                                              |       | —                                                               |       | 493                   |       |                |       |   |   |
| Less general  partner interest in net income                                         |       | 2,409                                                                |       | 464                   |       |                |       |   |   |
| **Limited  partners’ interest in net income**                                   |       | $                                                                    | 12,273     |                  | $          | 9,380               |       |   |   |   |   |
| **Net income per limited partners’ unit—basic**                            |       | $                                                                    | 1.37       |                  | $          | 1.33                |       |   |   |   |   |
| **Net income per limited partners’ unit—diluted**                          |       | $                                                                    | 1.36       |                  | $          | 1.32                |       |   |   |   |   |
| **Weighted average limited partners’ units  outstanding—basic**            |       | 8,961                                                                |       | 7,034                 |       |                |       |   |   |
| **Weighted  average limited partners’ units outstanding—diluted**          |       | 9,010                                                                |       | 7,086                 |       |                |       |   |   |

 

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

F-7

----

**HILAND PARTNERS, LP** Consolidated Statements of Cash Flows (in thousands, except unit amounts)

| ** **                                                                        | ** ** | ** **                                 | ** ** | ** **                             | ** ** | **Predecessor** | ** ** |
|-----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|----------------------------------------|------------|-----------------|------------|
| ** **                                                                        | ** ** | **Year Ended December 31,** | ** ** | **Year Ended  December 31,** | ** ** |
| ** **                                                                        | ** ** | **2006**                                   | ** ** | **2005**                               | ** ** | **2004**        | ** ** |
| **Cash flows from operating activities:**                                         | ** ** | ** **                                 | ** ** | ** **                             | ** ** |            | ** ** | ** ** |   |
| Net income                                                                        |       | $                                          | 14,682     |                                   | $          | 10,337          |       |   | $ | 4,912 |   |   |
| Adjustments to reconcile net income to net cash  provided byoperating activities: |       |                                       |       |                                   |       |            |       |   |   |
| Depreciation and  amortization                                                    |       | 22,064                                     |       | 11,083                                 |       |            | 4,170      |   |   |
| Accretion of asset  retirement obligation                                         |       | 66                                         |       | 8                                      |       |            | 23         |   |   |
| Amortization of  deferred loan cost                                               |       | 407                                        |       | 483                                    |       |            | 102        |   |   |
| Gain on hedge  ineffectiveness                                                    |       | (113                                       | )          | —                                 |       |            | —     |   |   |
| Unit based  compensation                                                          |       | 473                                        |       | 28                                     |       |            | —     |   |   |
| Gain on sale of  assets                                                           |       | —                                     |       | —                                 |       |            | (19        | ) |   |
| (Increase) decrease in current assets, net of  acquisition effects:               |       |                                       |       |                                   |       |            |       |   |   |
| Accounts  receivable—trade                                                   |       | (1,809                                     | )          | (17,507                                | )          |            | (1,831     | ) |   |
| Accounts  receivable—affiliates                                              |       | 239                                        |       | (765                                   | )          |            | (226       | ) |   |
| Inventories                                                                       |       | —                                     |       | 153                                    |       |            | 122        |   |   |
| Other current  assets                                                             |       | (330                                       | )          | (213                                   | )          |            | (113       | ) |   |
| Increase (decrease) in current liabilities, net of  acquisition effects:          |       |                                       |       |                                   |       |            |       |   |   |
| Accounts payable                                                                  |       | 5,708                                      |       | 782                                    |       |            | 319        |   |   |
| Accounts payable—affiliates                                                  |       | (1,710                                     | )          | 3,124                                  |       |            | 482        |   |   |
| Accrued  liabilities                                                              |       | 47                                         |       | 609                                    |       |            | 16         |   |   |
| Increase in other  assets                                                         |       | (144                                       | )          | —                                 |       |            | —     |   |   |
| **Net cash  provided by operating activities**                                    |       | 39,580                                     |       | 8,122                                  |       |            | 7,957      |   |   |
| **Cash flows from investing activities:**                                         | ** ** | ** **                                 | ** ** | ** **                             | ** ** |            | ** ** | ** ** |   |
| Additions to  property and equipment                                              |       | (62,137                                    | )          | (10,389                                | )          |            | (5,326     | ) |   |
| Payments for Kinta  Area assets acquired                                          |       | (96,400                                    | )          | —                                 |       |            | —     |   |   |
| Acquisition of net  assets of Hiland Partners, LLC, less cash received            |       | —                                     |       | (64,559                                | )          |            | —     |   |   |
| Proceeds from  disposals of property and equipment                                |       | 111                                        |       | 60                                     |       |            | 36         |   |   |
| **Net cash  used in investing activities**                                        |       | (158,426                                   | )          | (74,888                                | )          |            | (5,290     | ) |   |
| **Cash flows from financing activities:**                                         | ** ** | ** **                                 | ** ** | ** **                             | ** ** |            | ** ** | ** ** |   |
| Proceeds from  initial public offering—net                                   |       | —                                     |       | 48,128                                 |       |            | —     |   |   |
| Redemption of  common units from organizers                                       |       | —                                     |       | (6,278                                 | )          |            | —     |   |   |
| Distributions to  organizers                                                      |       | —                                     |       | (3,851                                 | )          |            | —     |   |   |
| Cash not  contributed by organizers                                               |       | —                                     |       | (869                                   | )          |            | —     |   |   |
| Payment of initial  public offering costs                                         |       | —                                     |       | (2,249                                 | )          |            | —     |   |   |
| Proceeds from  long-term borrowings                                               |       | 113,280                                    |       | 99,000                                 |       |            | 500        |   |   |
| Payments on  long-term borrowings                                                 |       | —                                     |       | (89,167                                | )          |            | (2,428     | ) |   |
| Increase in  deferred offering cost                                               |       | —                                     |       | —                                 |       |            | (1,012     | ) |   |
| Debt issuance  costs                                                              |       | (930                                       | )          | (1,332                                 | )          |            | (6         | ) |   |
| Proceeds from  secondary public offering—net                                 |       | —                                     |       | 66,071                                 |       |            | —     |   |   |
| Payment of  secondary public offering costs                                       |       | —                                     |       | (607                                   | )          |            | —     |   |   |
| Cash distribution  to controlling member for net assets of Hiland Partners, LLC   |       | —                                     |       | (27,768                                | )          |            | —     |   |   |
| General partner  contribution for issuance of restricted common units             |       | 12                                         |       | 7                                      |       |            | —     |   |   |
| Common units  issued to our general partner                                       |       | 35,000                                     |       | —                                 |       |            | —     |   |   |
| Proceeds from unit  options exercise                                              |       | 1,312                                      |       | —                                 |       |            | —     |   |   |
| Cash distribution  to unitholders                                                 |       | (25,629                                    | )          | (8,349                                 | )          |            | —     |   |   |
| **Net cash  provided by (used in) financing activities**                          |       | 123,045                                    |       | 72,736                                 |       |            | (2,946     | ) |   |
| Increase (decrease)  for the year                                                 |       | 4,199                                      |       | 5,970                                  |       |            | (279       | ) |   |
| Beginning of year                                                                 |       | 6,187                                      |       | 217                                    |       |            | 496        |   |   |
| **End of  year**                                                                  |       | $                                          | 10,386     |                                   | $          | 6,187           |       |   | $ | 217 |   |   |
| Supplementary information                                                         |       |                                       |       |                                   |       |            |       |   |   |
| Cash paid for  interest, net of amounts capitalized                               |       | $                                          | 4,514      |                                   | $          | 1,362           |       |   | $ | 787 |   |   |

 

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

F-8

----

**ConsolidatedStatements of Cash Flows (continued):**

| Non cash investing and  financing activities:                                                                                                                                    |   |   |   |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|--------|--------|
| Assumed asset retirement  obligations of $1,106 on May 1, 2006 in connection with the acquisition  of the Kinta Area gathering assets                                       |   |   |   |
| Fair value of net assets  acquired from Hiland Partners, LLC on February 15, 2005 in exchange for  252,927 common units and 1,433,251 subordinated units.                   |   |   |   |
| Accounts receivable and other current assets                                                                                                                                     |   | $      | 162    |   |
| Property and  equipment                                                                                                                                                          |   | 31,600 |   |
| Intangible assets                                                                                                                                                                |   | 26,800 |   |
| Other assets                                                                                                                                                                     |   | 105    |   |
| Total assets  acquired                                                                                                                                                           |   | 58,667 |   |
| Less accounts  payable and other current liabilities assumed                                                                                                                     |   | (741   | )      |
| Less current  portion of long-term debt assumed                                                                                                                                  |   | (8,879 | )      |
| Less asset  retirement obligation assumed                                                                                                                                        |   | (398   | )      |
| Fair value of net  assets acquired                                                                                                                                               |   | $      | 48,649 |   |
| Transfer to shareholder on May 31, 2004 of oil  and gas properties with a net book value of $2,489, accounts payable of  $298 and asset retirement obligations of $50. |   |   |   |

 

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

F-9

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**HILAND PARTNERS, LPConsolidated Statement of Changes in Owners’ Equity and Comprehensive IncomeFor the Years Ended December 31, 2006, 2005 and 2004**

| ** **                                                                                                                       | ** ** | **Hiland Partners, LP**                           | ** ** | ** ** | ** ** | ** **       | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|------------|------------|------------------|------------|
| ** **                                                                                                                       | ** ** | ** **                                                  | ** ** | ** ** | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | **Accumulated** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                                                       | ** ** | ** **                                                  | ** ** | ** ** | ** ** | ** **       | ** ** | **General** | ** ** | ** ** | ** ** | **Other** | ** ** | ** ** | ** ** | **Total** | ** ** |
| ** **                                                                                                                       | ** ** | **Predecessor**                                             | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **Partner** | ** ** | **Unearned** | ** ** | **Comprehensive** | ** ** | ** ** | ** ** | **Comprehensive** | ** ** |
| ** **                                                                                                                       | ** ** | **Equity**                                                  | ** ** | **Units**  | ** ** | **Units**        | ** ** | **Interest** | ** ** | **Compensation** | ** ** | **Income** | ** ** | **Total** | ** ** | **Income** | ** ** |
| ** **                                                                                                                       | ** ** | **(in thousands, except unit amounts)** | ** ** |
| Balance, January 1, 2004                                                                                                    |       |                                                        | $          | 21,739     |       |             |       | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | 21,739 |   |   |   |   |   |   |
| Net Income                                                                                                                       |       |                                                        | 4,912      |       |       |             |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   | 4,912 |   |   |   | $ | 4,912 |   |   |
| Transfer of discontinued operations to parent company                                                                            |       |                                                        | (2,141     | )          |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (2,141 | ) |   |   |   |   |   |
| Balance, December 31, 2004                                                                                                  |       |                                                        | 24,510     |       |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 24,510 |   |   |   |   |   |   |
| Assets not contributed to Hiland Partners, LP at  initial public  offering                                                  |       |                                                        | (9,972     | )          |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (9,972 | ) |   |   |   |   |   |
| Net income from January 1, 2005 through  February 14, 2005                                                             |       |                                                        | 493        |       |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 493 |   |   |   | 493 |   |   |
| Allocation of net parent investment to affiliated  unitholders (467,073 common units and 2,646,749 subordinated uints) |       |                                                        | (15,031    | )          |       |             | 2,191      |   |   |   | 12,418 |   |   |   | 422 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   |   |   |   |
| Contribution of certain net assets of Hiland  Partners, LLC by owners (252,927 common units and   1,433,251 subordinated units)  |       |                                                        | —     |       |       |             | 7,092      |   |   |   | 40,190 |   |   |   | 1,367 |   |   |   | — |   |   |   | — |   |   |   | 48,649 |   |   |   |   |   |   |
| Proceeds from initial public offering,  net of underwriter discount   (2,300,000 common units)                                   |       |                                                        | —     |       |       |             | 48,128     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 48,128 |   |   |   |   |   |   |
| Offering costs of initial public  offering                                                                                  |       |                                                        | —     |       |       |             | (3,365     | ) |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (3,365 | ) |   |   |   |   |   |
| Redemption of Common Units from Organizers (300,000  common units)                                                               |       |                                                        | —     |       |       |             | (6,278     | ) |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (6,278 | ) |   |   |   |   |   |
| Distributions to organizers                                                                                                      |       |                                                        | —     |       |       |             | (362       | ) |   |   | (3,489 | ) |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (3,851 | ) |   |   |   |   |   |
| Cash distribution to controlling   member for net assets of Hiland   Partners, LLC                                               |       |                                                        | —     |       |       |             | (2,507     | ) |   |   | (24,473 | ) |   |   | (788 | ) |   |   | — |   |   |   | — |   |   |   | (27,768 | ) |   |   |   |   |   |
| Contribution by general partner                                                                                                  |       |                                                        | —     |       |       |             | —     |   |   |   | — |   |   |   | 7 |   |   |   | — |   |   |   | — |   |   |   | 7 |   |   |   |   |   |   |
| Proceeds from secondary public offering, net of  underwriter discount (1,630,000 common units)                                   |       |                                                        | —     |       |       |             | 64,682     |   |   |   | — |   |   |   | 1,389 |   |   |   | — |   |   |   | — |   |   |   | 66,071 |   |   |   |   |   |   |
| Offering costs of secondary public offering                                                                                      |       |                                                        | —     |       |       |             | (607       | ) |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (607 | ) |   |   |   |   |   |
| Periodic cash distributions                                                                                                      |       |                                                        | —     |       |       |             | (3,268     | ) |   |   | (4,896 | ) |   |   | (185 | ) |   |   | — |   |   |   | — |   |   |   | (8,349 | ) |   |   |   |   |   |
| Issuance of restricted units (8,000 common  units)                                                                          |       |                                                        | —     |       |       |             | 317        |   |   |   | — |   |   |   | — |   |   |   | (317 | ) |   |   | — |   |   |   | — |   |   |   |   |   |   |
| Unit based compensation                                                                                                          |       |                                                        | —     |       |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | 28 |   |   |   | — |   |   |   | 28 |   |   |   |   |   |   |
| Change in fair value of derivatives                                                                                              |       |                                                        | —     |       |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 1,049 |   |   |   | 1,049 |   |   |   | 1,049 |   |   |
| Net income from February 15, 2005 through  December 31, 2005                                                           |       |                                                        | —     |       |       |             | 4,004      |   |   |   | 5,376 |   |   |   | 464 |   |   |   | — |   |   |   | — |   |   |   | 9,844 |   |   |   | 9,844 |   |   |
| Comprehensive Income                                                                                                             |       |                                                        |       |       |       |             |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   | $ | 11,386 |   |   |
| Balance, December 31, 2005                                                                                                  |       |                                                        | —     |       |       |             | 110,027    |   |   |   | 25,126 |   |   |   | 2,676 |   |   |   | (289 | ) |   |   | 1,049 |   |   |   | 138,589 |   |   |   |   |   |   |
| Elimination of unearned compensation upon adoption of  SFAS 123(R)                                                               |       |                                                        | —     |       |       |             | (289       | ) |   |   | — |   |   |   | — |   |   |   | 289 |   |   |   | — |   |   |   | — |   |   |   |   |   |   |
| Issuance of 761,714 common units to our general  partner                                                                         |       |                                                        | —     |       |       |             | 34,300     |   |   |   | — |   |   |   | 700 |   |   |   | — |   |   |   | — |   |   |   | 35,000 |   |   |   |   |   |   |
| Proceeds from 52,699 unit options exercise                                                                                       |       |                                                        | —     |       |       |             | 1,286      |   |   |   | — |   |   |   | 26 |   |   |   | — |   |   |   | — |   |   |   | 1,312 |   |   |   |   |   |   |
| Issuance of 13,000 restricted common units                                                                                       |       |                                                        | —     |       |       |             |       |   |   |   | — |   |   |   | 12 |   |   |   | — |   |   |   | — |   |   |   | 12 |   |   |   |   |   |   |
| Periodic cash distributions                                                                                                      |       |                                                        | —     |       |       |             | (12,690    | ) |   |   | (10,812 | ) |   |   | (2,127 | ) |   |   | — |   |   |   | — |   |   |   | (25,629 | ) |   |   |   |   |   |
| Unit based compensation                                                                                                          |       |                                                        | —     |       |       |             | 473        |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 473 |   |   |   |   |   |   |
| Other comprehensive income reclassified to income on  closed derivative transactions                                             |       |                                                        | —     |       |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | (3,582 | ) |   |   | (3,582 | ) |   |   | $ | (3,582 | ) |   |
| Change in fair value of derivatives                                                                                              |       |                                                        | —     |       |       |             | —     |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 6,889 |   |   |   | 6,889 |   |   |   | 6,889 |   |   |
| Net income                                                                                                                       |       |                                                        | —     |       |       |             | 6,674      |   |   |   | 5,599 |   |   |   | 2,409 |   |   |   | — |   |   |   | — |   |   |   | 14,682 |   |   |   | 14,682 |   |   |
| Comprehensive income                                                                                                             |       |                                                        |       |       |       |             |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   | $ | 17,989 |   |   |
| Balance,  December 31, 2006                                                                                                 |       |                                                        | $          | —     |       |             |       | $ | 139,781 |   |   |   | $ | 19,913 |   |   |   | $ | 3,696 |   |   |   | $ | — |   |   |   | $ | 4,356 |   |   |   | $ | 167,746 |   |   |   |   |   |   |

 

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

F-10

----

**HILAND PARTNERS, LPNOTES TO CONSOLIDATED FINANCIAL STATEMENTSDecember 31, 2006 and 2005(in thousands, except unit and per unit information or unless otherwise noted)**

**Note 1:   Descriptionof Business and Summary of Significant Accounting Policies**

***Description of Business***

Hiland Partners, LP, a Delaware limitedpartnership (“we,” “us,” “our,” “HPLP” or “the Partnership”), was formed in October 2004to acquire and operate certain midstream natural gas plants, gathering systemsand compression and water injection assets located in the states of Oklahoma,North Dakota, Wyoming, Texas and Mississippi that were previously owned byContinental Gas, Inc. (“Predecessor” or “CGI”) and HilandPartners, LLC. We commenced operations on February 15, 2005, andconcurrently with the completion of our initial public offering, CGIcontributed a substantial portion of its net assets to us.

CGI constitutes our predecessor. The transfer ofownership of net assets from CGI to us represented a reorganization of entitiesunder common control and was recorded at historical cost. Accordingly, thefinancial statements include the historical operations of CGI prior to thetransfer to us. CGI was formed in 1990 as a wholly owned subsidiary ofContinental Resources, Inc. (“CRI”).

CGI operated in one segment, midstream, which involvedthe gathering, compressing, dehydrating, treating, and processing of naturalgas and fractionating natural gas liquids, or NGLs. CGI historically has ownedall of our natural gas gathering, processing, treating and fractionation assetsother than our Worland gathering system and our Bakken gathering system. HilandPartners, LLC historically owned our Worland gathering system and ourcompression services assets, which we acquired on February 15, 2005, andour Bakken gathering system. Since our initial public offering, we haveoperated in midstream and compression services segments. On September 26,2005, we acquired Hiland Partners, LLC, which at such time owned theBakken gathering system, for $92.7 million, $35.0 million of whichwas 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 $96.4million. We financed this acquisition with $61.2 million of borrowings from ourcredit facility and $35.0 million of proceeds from the issuance to HilandPartners GP, LLC, our general partner, of 761,714 common units and 15,545general partner equivalent units, both at $45.03 per unit.

CGI had minor interests in producing oil and gasproperties located primarily in North Dakota. The properties were acquired overseveral years while CGI was a subsidiary of CRI. CGI did not intend to pursuethe exploration for and development of oil and natural gas and, accordingly,conveyed its interest in these properties effective May 31, 2004 to CRI.Therefore, this activity is presented as discontinued operations.

In July 2004, CRIsold all of the issued and outstanding capital stock of CGI to the shareholdersof CRI at fair value. The stock sale transaction was approved by all of theindependent members of the Board of Directors of CRI, and the independentmembers of the Board of Directors were provided with an opinion as to thefairness of the stock sale transaction, from a financial point of view. CGI andCRI were previously consolidated and subsequently were affiliated corporationsbecause of common ownership.

F-11

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***Principles of Consolidation***

The consolidated financialstatements include our accounts and those of our subsidiaries. All significantintercompany transactions and balances have been eliminated. The consolidatedfinancial statements include the net assets and operations of assets owned byCGI and Hiland Partners, LLC that were contributed to us concurrently withthe completion of our initial public offering and also include the net assetsand operations of Hiland Partners, LLC acquired effective September 1,2005.

***Use of Estimates***

The preparation offinancial statements in accordance with accounting principles generallyaccepted in the United States of America requires management to make estimatesand assumptions that affect the amounts reported in the financial statementsand accompanying notes. Actual results could differ from those estimates.

***Cash and Cash Equivalents***

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

***Accounts Receivable***

The majority of ouraccounts receivable are due from companies in the oil and gas industry as wellas the utility industry. Credit is extended based on evaluation of the customer’sfinancial condition. In certain circumstances, collateral, such as letters ofcredit or guarantees, is required. Accounts receivable are due within30 days and are stated at amounts due from customers. We have establishedvarious procedures to manage our credit exposure, including initial creditapprovals, credit limits and rights of offset. Credit losses are charged toincome when accounts are deemed uncollectible, determined on a case-by-casebasis when we believe the required payment of specific amounts owed is unlikelyto occur. These losses historically have been minimal. Therefore, an allowancefor uncollectible accounts is not required.

***Concentration and Credit Risk***

Financial instruments thatpotentially subject us to concentrations of credit risk consist principally ofcash and cash equivalents and receivables. We place our cash and cashequivalents with high-quality institutions and in money market funds. We deriveour revenue from customers primarily in the natural gas and utility industries.These industry concentrations have the potential to impact our overall exposureto credit risk, either positively or negatively, in that our customers could beaffected by similar changes in economic, industry or other conditions. However,we believe that the credit risk posed by this industry concentration is offsetby the creditworthiness of our customer base. Our portfolio of accountsreceivable is comprised primarily of mid-size to large domestic corporateentities.

***Fair Value of Financial Instruments***

Our financial instruments,which require fair value disclosure, consist primarily of cash and cashequivalents, accounts receivable, financial derivatives, accounts payable andlong-term debt. The carrying value of cash and cash equivalents, accountsreceivable and accounts payable are considered to be representative of theirrespective fair values, due to the short maturity of these instruments.Derivative instruments are reported in the accompanying consolidated financialstatements at fair value in accordance with Statement of Financial AccountingStandards (“SFAS”) No. 133, “Accounting for Derivative Instruments and HedgingActivities,” as amended. Fairvalue of our derivative instruments is determined based on management estimatesthrough utilization of market data including forecasted forward natural 

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gas and NGL prices as a function of forward NYMEXnatural gas and light crude prices. The fair value of long-term debtapproximates its carrying value due to the variable interest rate feature ofsuch debt.

***Commodity Risk Management***

We engage in price risk management activities in orderto minimize the risk from market fluctuation in the price of natural gas. Toqualify as a hedge, the price movements in the commodity derivatives must behighly correlated with the underlying hedged commodity. Gains and lossesrelated to commodity derivatives which qualify as hedges are recognized inincome when the underlying hedged physical transaction closes and are includedin the consolidated statements of operations as revenues from midstreamoperations.

Statement of Financial Accounting Standards (“SFAS”) No. 133,“Accounting for Derivative Instruments and Hedging Activities,” as amended,establishes accounting and reporting standards for derivative instruments,including certain derivative instruments embedded in other contracts, and forhedging activities. SFAS No. 133 requires that an entity recognize allderivatives as either assets or liabilities in the statement of financialposition and measure those instruments at fair value. However, if a derivativedoes qualify for hedge accounting, depending on the nature of the hedge, changesin fair value can be offset against the change in fair value of the hedged itemthrough earnings or recognized in other comprehensive income until such time asthe hedged item is recognized in earnings. To qualify for cash flow hedgeaccounting, the cash flows from the hedging instrument must be highly effectivein offsetting changes in cash flows due to changes in the underlying item beinghedged. In addition, all hedging relationships must be designated, documented,and reassessed periodically. SFAS No. 133 also provides that normalpurchases and normal sales contracts are not subject to the statement. Normalpurchases and normal sales are contracts that provide for the purchase or saleof something other than a financial instrument or derivative instrument thatwill be delivered in quantities expected to be used or sold by the reportingentity over a reasonable period in the normal course of business. Our forwardnatural gas purchase and sales contracts are designated as normal purchases andsales. Substantially all forward contracts fall within a one to 24 month term.

Currently, our derivativefinancial instruments that qualify for hedge accounting are designated as cashflow hedges. The cash flow hedge instruments hedge the exposure of variabilityin expected future cash flows that is attributable to a particular risk. Theeffective portion of the gain or loss on these derivative instruments isrecorded in accumulated other comprehensive income in partners’ equity andreclassified into earnings in the same period in which the hedged transactioncloses. The asset or liability related to the derivative instruments isrecorded on the balance sheet as fair value of derivative assets orliabilities. Any ineffective portion of the gain or loss is recognized in earningsimmediately.

***Property and Equipment***

Our property and equipmentare carried at cost. Depreciation and amortization of all equipment isdetermined under the straight-line method using various rates based on usefullives, 10 to 22 years for pipeline and processing plants, and 3 to10 years for corporate and other assets. The cost of assets and relatedaccumulated depreciation is removed from the accounts when such assets aredisposed of, and any related gains or losses are reflected in current earnings.Maintenance, repairs and minor replacements are expensed as incurred. Costs ofreplacements constituting improvement are capitalized.

***Intangible Assets***

Intangibleassets consist of the acquired value of existing contracts to sell natural gasand other NGLs and compression contracts, which do not have significantresidual value. The contracts are being amortized over their estimated lives often years. We review intangible assets for impairment whenever events or 

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circumstances indicate that the carrying amounts maynot be recoverable. If such a review should indicate that the carrying amountof intangible assets is not recoverable, we reduce the carrying amount of suchassets to fair value based on the discounted probable cash flows of theintangible assets. No impairments of intangible assets were recorded during theyears ended December 31, 2006, 2005 and 2004. On May 1, 2006 weacquired the Kinta Area gathering assets and recorded identifiable customerrelationships of $10,492. Intangible assets consisted of the following for theperiods indicated:

|                                | ** ** | **As of**        | ** ** | **As of**        | ** ** |
|--------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                     | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
| ** **                     | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| Gas sales  contracts           |       |                  | $          | 25,585                |       |   |   | $ | 25,585 |   |   |
| Compression  contracts         |       |                  | 18,515     |                  |       |   | $ | 18,515 |   |   |
| Customer  relationships        |       |                  | 10,492     |                  |       |   | — |   |   |
|                           |       |                  | 54,592     |                  |       |   | 44,100 |   |   |
| Less accumulated  amortization |       |                  | 8,031      |                  |       |   | 2,921 |   |   |
| Intangible assets, net         |       |                  | $          | 46,561                |       |   |   | $ | 41,179 |   |   |

 

During the years ended December 31,2006 and 2005 we recorded $5,110 and $2,921, respectively of amortizationexpense. We had no intangible assets prior to February 15, 2005. Estimatedaggregate amortization expense for each of the five succeeding fiscal years is$5,459 from 2007 through 2011 and a total of $19,266 for all years thereafter.

***Long-Lived Assets***

In accordance with Statement of Financial AccountingStandards (SFAS) No. 144, “Accounting for the Impairment or Disposal ofLong-Lived Assets”, we evaluate our long-lived assets of identifiable businessactivities for impairment when events or changes in circumstances indicate, inour management’s judgment, that the carrying value of such assets may not berecoverable. The determination of whether impairment has occurred is based onour management’s estimate of undiscounted future cash flows attributable to theassets as compared to the carrying value of the assets. If impairment hasoccurred, the amount of the impairment recognized is determined by estimatingthe fair value for the assets and recording a provision for loss if thecarrying value is greater than fair value. For assets identified to be disposedof in the future, the carrying value of these assets is compared to theestimated fair value less the cost to sell to determine if impairment isrequired. Until the assets are disposed of, an estimate of the fair value isre-determined when related events or circumstances change.

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

·       changes in general economicconditions in regions in which the Partnership’s assets are located;

·       the availability and pricesof NGL products and competing commodities;

·       the availability and pricesof raw natural gas supply;

·       our ability to negotiatefavorable marketing agreements;

·       the risks that third partyoil and gas exploration and production activities will not occur or besuccessful;

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·       our dependence on certainsignificant customers and producers of natural gas; and

·       competition from othermidstream service providers and processors, including major energy companies.

Any significant variance in any of the above assumptionsor factors could materially affect our cash flows, which could require us torecord an impairment of an asset.

No impairment charges wererecognized during each of the years ended December 31, 2006, 2005 and 2004.

***Other Assets***

Unamortized deferred loancosts related to the long-term debt on our bank credit facility totaling $1,550and $1,028 as of December 31, 2006 and 2005, respectively, are included inother noncurrent assets. The deferred loan costs are amortized using thestraight-line method over the term of the debt for the bank credit facility.

***Revenue Recognition***

Revenues for sales andgathering of natural gas and NGLs are recognized at the time all gathering andprocessing activities are completed, the product is delivered and title, ifapplicable, is transferred. Revenues from oil and gas production (discontinuedoperations) are recorded in the month produced and title is transferred to thepurchaser. Revenues related to our compression segment are recognized asmonthly services are rendered under a four-year fixed-fee contract that weentered into concurrently with our initial public offering.

***Comprehensive Income***

Comprehensive incomeincludes net income and other comprehensive income, which includes, but is notlimited to, changes in the fair value of derivative financial instruments.Pursuant to SFAS No. 133, for derivatives qualifying as hedges, theeffective portion of changes in fair value are recognized in owners’ equity asaccumulated other comprehensive income and reclassified to earnings when theunderlying hedged physical transaction closes.

***Net Income per Limited Partners’ Unit***

Net income per limitedpartners’ unit is computed based on the weighted-average number of common andsubordinated units outstanding during the period. The computation of dilutednet income per limited partner unit further assumes the dilutive effect of unitoptions and restricted units. Net income per limited partners’ unit is computedby dividing net income applicable to limited partners, after deducting the generalpartner’s 2% interest and incentive distributions, and, for 2005, afterdeducting net income attributable to the Predecessor (before February 15,2005), by both the basic and diluted weighted-average number of limitedpartnership units outstanding.

***Environmental Costs***

Environmental costs areexpensed if they relate to an existing condition caused by past operations anddo not contribute to current or future revenue generation. Liabilities arerecorded when site restoration and environmental remediation and cleanupobligations are either known or considered probable and can be reasonablyestimated. Recoveries of environmental costs through insurance, indemnificationarrangements or other sources are included in other assets to the extent suchrecoveries are considered probable.

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***Income Taxes***

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

Net income for financialstatement purposes may differ significantly from taxable income reportable tounitholders as a result of differences between the tax basis and financialreporting basis of assets and liabilities and the taxable income allocationrequirements under the partnership agreement. Individual unitholders havedifferent investment bases depending upon the timing and price of acquisitionof their partnership units. Furthermore, each unitholder’s tax accounting,which is partially dependent upon the unitholder’s tax position, differs fromthe accounting followed in the consolidated financial statements. Accordingly,the aggregate difference in the basis of our net assets for financial and taxreporting purposes cannot be readily determined because information regardingeach unitholder’s tax attributes in our partnership is not available to us.

***Transportation and Exchange Imbalances***

In the course oftransporting natural gas and NGLs for others, we may receive for redeliverydifferent quantities of natural gas or NGLs than the quantities actuallyredelivered. These transactions result in transportation and exchange imbalancereceivables or payables that are recovered or repaid through the receipt ordelivery of natural gas or NGLs in future periods, if not subject to cashoutprovisions. Imbalance receivables are included in accounts receivable andimbalance payables are included in accounts payable on the balance sheets and marked-to-marketusing current market prices in effect for the reporting period of theoutstanding imbalances. Changes in market value and the settlement of any suchimbalance at a price greater than or less than the recorded imbalance resultsin either an upward or downward adjustment, as appropriate, to the cost ofnatural gas sold. As of December 31, 2006 we had imbalance receivables of$1,028 and no imbalance payables. As of December 31, 2005, we had noimbalance receivables or payables.

***Share-Based Compensation***

Our general partner, Hiland Partners GP, LLC adoptedthe Hiland Partners, LP Long-Term Incentive Plan for its employees anddirectors of our general partner and employees of its affiliates. The long-termincentive plan currently permits an aggregate of 680,000 common units to beissued with respect to unit options, restricted units, and phantom unitsgranted under the plan. No more than 225,000 of the 680,000 common units may beissued with respect to vested restricted or phantom units. The plan is administeredby the compensation committee of our general partner’s board ofdirectors. The plan will continue in effect until the earliest of (i) thedate determined by the board of directors of our general partner; (ii) thedate that common units are no longer available for payment of awards under theplan; or (iii) the tenth anniversary of the plan.

Our general partner’s board of directors orcompensation committee may, in their discretion, terminate, suspend ordiscontinue the long-term incentive plan at any time with respect to any unitsfor which a grant has not yet been made. Our general partner’s board ofdirectors or its compensation committee also has the right to alter or amendthe 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 tounitholder approval if required by the exchange upon which the common units arelisted at that time. No change in any outstanding grant may be made, however,that would materially impair the rights of the participant without the consentof the participant. Under the unit option grant agreement, granted options ofcommon units will vest and become exercisable in one-third increments on theanniversary of the grant date over three years. Vested options are exercisablewithin the option’s contractual life of ten years after the grant date.

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In October 1995the FASB issued SFAS No. 123, “Share-Based Payment,” which was revised in December 2004(“SFAS 123R”). SFAS 123R requires that the compensation cost relating toshare-based payment transactions be recognized in the financial statements andthat cost be measured based on the fair value of the equity or liabilityinstruments issued. We adopted SFAS 123R as of January 1, 2006 and appliedSFAS 123R using the permitted modified prospective method beginning as of thesame 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 awardsas unearned compensation in equity. We expect no change to our cash flowpresentation from the adoption of SFAS 123R since no tax benefits arerecognized by us as a pass through entity. Our compensation expense for theseawards is recognized on the graded vesting attribution method. Units to beissued under our unit incentive plan may be from newly issued units. Nocompensation expense was recognized in 2005 for our unit options granted during2005. Prior to our adoption of SFAS 123R on January 1, 2006, we appliedAccounting Principles Board Opinion No. 25 and related interpretations inaccounting for our unit-based compensation awards. The following pro forma datawas calculated as if compensation cost for our unit-based compensation awardsduring the year ended December 31, 2005 was determined based upon the fairvalue at the grant date consistent with the methodology prescribed under SFAS No. 123.

|                                                                 | ** ** | **Year Ended**   | ** ** |
|-----------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                      | ** ** | **December 31,** | ** ** |
| ** **                                                      | ** ** | **2005**              | ** ** |
| Net income as reported                                          |       |                  | $          | 10,337 |   |   |
| Share based compensation  adjustment                            |       |                  | (419       | ) |   |
| Pro forma net income                                            |       |                  | 9,918      |   |   |
| Less income attributable  to predecessor                        |       |                  | (493       | ) |   |
| Less general partner  interest                                  |       |                  | (447       | ) |   |
| Limited partner’s  interest in pro forma net income        |       |                  | $          | 8,978 |   |   |
| Net income per limited  partner unit as reported—basic     |       |                  | $          | 1.33 |   |   |
| Net income per limited  partner unit as reported—diluted   |       |                  | $          | 1.32 |   |   |
| Adjustment—basic                                           |       |                  | $          | (0.05 | ) |   |
| Adjustment—diluted                                         |       |                  | $          | (0.05 | ) |   |
| Proforma net income per  limited partner unit—basic        |       |                  | $          | 1.28 |   |   |
| Proforma net income per  limited partner unit—diluted      |       |                  | $          | 1.27 |   |   |
| Weighted average limited  partner units outstanding—basic  |       |                  | 7,034,000  |   |   |
| Weighted average limited partner units outstanding—diluted |       |                  | 7,086,000  |   |   |

 

Thefair value of each option granted was estimated on the date of grant using theAmerican Binomial option-pricing model that used the assumptions noted below.Expected and weighted-average volatility is based on our peer group volatilityaverages as determined on the option grant dates. Expected volatility ofoptions granted ranged from 16% to 31% and weighted-average volatility rangedfrom 18% to 30%. For options granted in 2006 and 2005, expected lives of6.0 years are calculated by the simplified method as prescribed under SECStaff Accounting Bulletin 107 and represent the period of time that unitoptions granted are expected to be outstanding. The risk-free interest rate forperiods within the contractual life of the option is based on the U.S. Treasuryyield in effect at the time of grant. The exercise price of the options grantedequaled the market price of the units on the grant date.

|                             | ** ** | **Year Ended**   | ** ** | **Year Ended**   | ** ** |
|-----------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                  | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
| ** **                  | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| Expected volatility         |       | 16.1% - 20.2          | %          | 20.2% - 31.0          | %          |
| Weighted-average volatility |       | 18.0                  | %          | 29.4                  | %          |
| Expected dividend yield     |       | 6.4                   | %          | 5.2                   | %          |
| Risk-free interest rate     |       | 4.5                   | %          | 4.5                   | %          |

 

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Thefollowing table summarizes information about outstanding options for the yearended December 31, 2006.

|                                        | ** ** | ** ** | ** ** | ** **   | ** ** | **Weighted-**      | ** ** | ** **            | ** ** |
|----------------------------------------|------------|------------|------------|--------------|------------|--------------------|------------|-----------------------|------------|
| ** **                             | ** ** | ** ** | ** ** | **Weighted** | ** ** | **Average**        | ** ** | ** **            | ** ** |
| ** **                             | ** ** | ** ** | ** ** | **Average**  | ** ** | **Remaining**      | ** ** | **Aggregate**         | ** ** |
| ** **                             | ** ** | ** ** | ** ** | **Exercise** | ** ** | **Contractual**    | ** ** | **Intrinsic**         | ** ** |
| **Options**                            | ** ** | ** ** | ** ** | **Units**    | ** ** | **Price ($)** | ** ** | **Term (Years)** | ** ** | **Value ($)** | ** ** |
| Outstanding at  January 1, 2006   |       | 167,500    |       |         | $          | 24.70              |       |                  |       |   |   |   |   |   |   |   |
| Granted                                |       | 28,000     |       |         | $          | 39.78              |       |                  |       |   |   |   |   |   |   |   |
| Exercised                              |       | (52,699    | )          |         | $          | 24.40              |       |                  |       |   |   |   |   | $ | 876 |   |   |
| Forfeited or expired                   |       | (14,333    | )          |         | $          | 23.53              |       |                  |       |   |   |   |   |   |   |   |
| Outstanding at December 31, 2006  |       | 128,468    |       |         | $          | 28.24              |       |                  |       | 8.4 |   |   |   | $ | 2,355 |   |   |
| Exercisable at  December 31, 2006 |       | 2,801      |       |         | $          | 28.79              |       |                  |       | 8.1 |   |   |   | $ | 50 |   |   |
|                                        |            |            |            |              |            |                    |            |                       |            |  |  |  |  |  |  |  |  |  |  |

 

The weighted average grant date fair value of the55,500 unit options vested during the year ended December 31, 2006 was$5.15 per unit. The weighted average grant date fair value of the 28,000 unitoptions granted during the year ended December 31, 2006 was $4.33 perunit. The weighted average grant date fair value of 167,500 unit optionsgranted during the year ended December 31, 2005 was $5.30 per unit. As of December 31,2006, there was $214 of total unrecognized compensation cost related tounvested unit based option awards granted under our Plan. This cost is expectedto be recognized over a weighted-average period of 1.2 years.

On April 14, 2006, 13,333 of the unit optionsissued on February 10, 2005, were forfeited. We assumed no forfeitures inour fair value calculations, as we believe this forfeiture is an isolatedincident and is not indicative of the future. Compensation expense for the yearended December 31, 2006 has been reduced by $21 as a result of the forfeiture.

As a result of adopting SFAS 123R on the modifiedprospective basis beginning on January 1, 2006, we expensed $354 relatedto unit options that were awarded in both 2006 and 2005. We recognized no unitoption compensation expense in 2005. Basic and diluted earnings per unit wereeach reduced by $0.04 for the year ended December 31, 2006 as a result ofthe additional compensation recognized under SFAS 123R.

Thefollowing table summarizes information about restricted units for the yearended December 31, 2006.

| ** **                            | ** ** | ** ** | ** ** | **Weighted**        | ** ** |
|---------------------------------------|------------|------------|------------|---------------------|------------|
| ** **                            | ** ** | ** ** | ** ** | **Average**         | ** ** |
| ** **                            | ** ** | ** ** | ** ** | **Fair Value** | ** ** |
| ** **                            | ** ** | ** ** | ** ** | **At Grant**   | ** ** |
| **Restricted Units**             | ** ** | ** ** | ** ** | **Units**           | ** ** | **Date ($)** | ** ** |
| Non-vested at  January 1, 2006   |       | 8,000      |       |                | $          | 39.69 |   |   |
| Granted                               |       | 13,000     |       |                | $          | 46.17 |   |   |
| Vested                                |       | (2,000     | )          |                | $          | 39.69 |   |   |
| Forfeited                             |       | —     |       |                |       |   |   |
| Non-vested at  December 31, 2006 |       | 19,000     |       |                | $          | 44.12 |   |   |
|                                       |            |            |            |                     |            |  |  |  |  |  |

 

During 2006, we issued (i) 1,000 units each tofour non-employee board members of our general partner on their one-yearanniversary dates, (ii) 2,000 units each on August 11, 2006 to twonewly elected non-employee board members of our general partner, (iii) 3,000units to an executive officer of our general 

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partner and (iv) 2,000units to certain employees of our general partner. Our general partnercontributed $12 to us to maintain its 2% ownership interest.

Also during 2006, one fourth, or 2,000, of the 8,000restricted units we issued to non-employee board members of our general partnerin 2005 vested and were converted to common units. The weighted average grantdate fair value of the restricted units issued in 2005 was $39.69 per unit.

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

Total compensation expenserelated to restricted units was $119 and $28 for the years ended December 31,2006 and 2005, respectively. As of December 31, 2006, there was $770 oftotal unrecognized cost related to unvested restricted units. This cost is tobe recognized over a weighted average period of 3.3 years.

***Accounting for Asset Retirement Obligations***

In accordance with SFAS No. 143, “Accounting forAsset Retirement Obligations,” we have recorded the fair value of liabilitiesfor asset retirement obligations in the periods in which they are incurred andcorresponding increases in the carrying amounts of the related long-livedassets. The asset retirement costs are subsequently allocated to expense usinga systematic and rational method and the liabilities are accreted to measurethe change in liability due to the passage of time. The provisions of thisstandard primarily apply to dismantlement and site restoration of certain ofour plants and pipelines. We have evaluated our asset retirement obligations asof December 31, 2006 and have determined that revisions in the carryingvalues are not necessary at this time.

Thefollowing table summarizes our activity related to asset retirementobligations:

| Asset retirement obligation,  January 1, 2005                 |   | $     | 619    |   |
|--------------------------------------------------------------------|--------|-------|--------|--------|
| Add: acquired  from Hiland Partners, LLC on February 15, 2005 |   | 398   |   |
| Add: accretion  expense                                            |   | 27    |   |
| Less: revisions                                                    |   | (20   | )      |
| Asset retirement  obligation, December 31, 2005               |   | 1,024 |   |
| Acquired in Kinta  Area asset acquisition on May 1, 2006      |   | 1,106 |   |
| Add: accretion  expense                                            |   | 66    |   |
| Asset retirement  obligation, December 31, 2006               |   | $     | 2,196  |   |

 

***Recently Issued Accounting Pronouncements***

In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities”. SFAS No. 159expands opportunities to use fair value measurement in financial reporting andpermits entities to choose to measure many financial instruments and certainother items at fair value. SFAS No. 159 is effective for fiscal yearsbeginning after November 15, 2007. We have not decided if we will earlyadopt SFAS No. 159 or if we will choose to measure any eligible financialassets and liabilities at fair value.

In September 2006, the FASB issued SFAS No. 157“Fair Value Measurements.”  SFAS No. 157defines fair value as the price that would be received to sell an asset or paidto transfer a liability in an orderly transaction between market participantsat the measurement date, establishes a framework for measuring fair value ingenerally accepted accounting principles (GAAP) such as fair value hierarchyused 

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to classify the source ofinformation used in fair value measurements (i.e., market based or non-marketbased) and expands disclosure about fair value measurements based on theirlevel in the hierarchy. This Statement applies to derivatives and otherfinancial instruments, which Statement 133, *Accountingfor Derivative Instruments and Hedging Activities*, as amendedrequires be measured at fair value at initial recognition and for allsubsequent periods. This Statement is effective for financial statements issuedfor fiscal years beginning after November 15, 2007 and interim periodswithin those fiscal years. We will apply the provisions of the Statementprospectively in our first interim period in the fiscal year beginning on January 1,2008 and we do not expect a change in our methodologies of fair valuemeasurements.

In September 2006,the SEC staff issued Staff Accounting Bulletin No. 108, “Considering theEffects of Prior Year Misstatements when Quantifying Misstatements in CurrentYear Financial Statements.”  SAB 108 wasissued to provide consistency between how registrants quantify financialstatement misstatements. Historically, there have been two widely used methodsfor quantifying the effects of financial statement misstatements. These methodsare referred to as the “roll-over” and “iron curtain” method. The roll-overmethod quantifies the amount by which the current year income statement ismisstated. Exclusive reliance on an income statement approach can result in theaccumulation of errors on the balance sheet that may not have been material toany individual income statement, but which may misstate one or more balancesheet accounts. The iron curtain method quantifies the error as the cumulativeamount by which the current year balance sheet is misstated. Exclusive relianceon a balance sheet approach can result in disregarding the effects of errors inthe current year income statement that results from the correction of an errorexisting in previously issued financial statements. SAB 108 established anapproach that requires quantification of financial statement misstatementsbased on the effects of the misstatement on each of the company’s financialstatements and the related financial statement disclosures. This approach iscommonly referred to as the “dual approach” because it requires quantificationof errors under both the roll-over and iron curtain methods. We applied themethodology consistent with SAB 108 in connection with the preparation of theseannual financial statements for the year ending December 31, 2006 and didnot record an adjustment.

**Note 2:   InitialFormation and Contribution of Assets**

In connection with our formation and our initialpublic offering on February 15, 2005, the assets and liabilities of CGIexcluding certain working capital assets were contributed to us in exchange for271,082 of our common units, after redemption of 195,991 common units, and2,646,749 of our subordinated units. Existing bank debt of CGI was repaid fromthe proceeds of our initial public offering.

All of our initial assets were contributed by theformer owners of CGI, Hiland Partners, LLC, and certain affiliates, includingour general partner, in exchange for an aggregate of 720,000 common units and4,080,000 subordinated units, a 2% general partner interest in us and all ofour incentive distribution rights, which entitle the general partner toincreasing percentages of the cash we distribute in excess of $0.495 per unit perquarter. The assets of CGI transferred to us are recorded at historical cost asit is considered to be a reorganization of entities under common control andCGI is considered our accounting predecessor. The acquisition of the assets ofHiland Partners, LLC was accounted for as a purchase and, as a result, theseassets were recorded at their fair value at the time of purchase.

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The following tablepresents the assets and liabilities of our predecessor immediately prior tocontributing assets to us, assets and liabilities contributed to us, and ourpredecessor’s assets and liabilities not contributed to us.

**ContinentalGas, Inc. (Predecessor)Assets Contributed to Hiland Partners, LPAs of February 15, 2005(in thousands)**

| ** **                                 | ** ** | **Continental Gas, Inc.** | ** ** | **Net Assets** | ** ** | **Contributed to**           | ** ** |
|--------------------------------------------|------------|-------------------------------------|------------|---------------------|------------|-----------------------------------|------------|
| ** **                                 | ** ** | **(Predecessor)**                   | ** ** | **Not**             | ** ** | **Hiland Partners, LP** | ** ** |
| ** **                                 | ** ** | **February 14, 2005**     | ** ** | **Contributed**     | ** ** | **February 15, 2005**   | ** ** |
| **ASSETS**                                 | ** ** |                                | ** ** | ** **          |       |                              | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Current assets:                            |       |                                |       | ** **          |       |                              |       | ** ** |   |   |   | ** ** |   |
| Cash and cash  equivalents                 |       |                                | $          | 869                 | ** ** |                              |       | $ | 869 | ** ** |   |   | $ | — | ** ** |   |
| Accounts receivable                        |       |                                | 10,521     | ** **          |       |                              | 9,101      | ** ** |   |   | 1,420 | ** ** |   |
| Inventories                                |       |                                | 153        | ** **          |       |                              | —     | ** ** |   |   | 153 | ** ** |   |
| Other current  assets                      |       |                                | 291        | ** **          |       |                              | 2          | ** ** |   |   | 289 | ** ** |   |
| Total current assets                       |       |                                | 11,834     | ** **          |       |                              | 9,972      | ** ** |   |   | 1,862 | ** ** |   |
| Property and  equipment, at cost, net      |       |                                | 36,805     | ** **          |       |                              | —     | ** ** |   |   | 36,805 | ** ** |   |
| Other assets, net                          |       |                                | 3,388      | ** **          |       |                              | —     | ** ** |   |   | 3,388 | ** ** |   |
| Total assets                               |       |                                | 52,027     | ** **          |       |                              | 9,972      | ** ** |   |   | 42,055 | ** ** |   |
| **LIABILITIES**                            | ** ** |                                | ** ** | ** **          |       |                              | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Current liabilities:                       |       |                                |       | ** **          |       |                              |       | ** ** |   |   |   | ** ** |   |
| Accounts payable                           |       |                                | 11,703     | ** **          |       |                              | —     | ** ** |   |   | 11,703 | ** ** |   |
| Accrued  liabilities                       |       |                                | 700        | ** **          |       |                              | —     | ** ** |   |   | 700 | ** ** |   |
| Current  maturities of long term debt      |       |                                | 2,429      | ** **          |       |                              | —     | ** ** |   |   | 2,429 | ** ** |   |
| Total current  liabilities                 |       |                                | 14,832     | ** **          |       |                              | —     | ** ** |   |   | 14,832 | ** ** |   |
| Commitments and  contingencies             |       |                                |       | ** **          |       |                              |       | ** ** |   |   |   | ** ** |   |
| Long term debt,  net of current maturities |       |                                | 11,570     | ** **          |       |                              | —     | ** ** |   |   | 11,570 | ** ** |   |
| Asset retirement  obligation               |       |                                | 622        | ** **          |       |                              | —     | ** ** |   |   | 622 | ** ** |   |
| Total liabilities                          |       |                                | 27,024     | ** **          |       |                              | —     | ** ** |   |   | 27,024 | ** ** |   |
| **NET  ASSETS**                            |       |                                | $          | 25,003              | ** ** |                              |       | $ | 9,972 | ** ** |   |   | $ | 15,031 | ** ** |   |

 

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

F-21

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

**HilandPartners, LLCAssets Contributed to Hiland Partners, LPAs of February 15, 2005(in thousands)**

| ** **                                  | ** ** | ** **                         | ** ** | **Net Assets** | ** ** | **Contributed to**           | ** ** | ** ** | ** ** |
|---------------------------------------------|------------|------------------------------------|------------|---------------------|------------|-----------------------------------|------------|------------|------------|
| ** **                                  | ** ** | **Hiland Partners, LLC** | ** ** | **Not**             | ** ** | **Hiland Partners, LP** | ** ** | **Fair**   | ** ** |
| ** **                                  | ** ** | **February 14, 2005**    | ** ** | **Contributed**     | ** ** | **February 15, 2005**   | ** ** | **Value**  | ** ** |
| **ASSETS**                                  | ** ** |                               | ** ** | ** **          |       |                              | ** ** | ** ** |       |   | ** ** | ** ** |   | ** ** | ** ** |
| Current assets:                             |       |                               |       | ** **          |       |                              |       | ** ** |       |   |   | ** ** |   |   |   |
| Cash and cash  equivalents                  |       |                               | $          | 964                 | ** ** |                              |       | $          | 964        | ** ** |   |   | $ | — | ** ** |   | $ | — |   |
| Accounts receivable                         |       |                               | 2,619      | ** **          |       |                              | 2,503      | ** ** |       |   | 116 | ** ** |   | 116 |   |
| Other current  assets                       |       |                               | 56         | ** **          |       |                              | 10         | ** ** |       |   | 46 | ** ** |   | 46 |   |
| Total current assets                        |       |                               | 3,639      | ** **          |       |                              | 3,477      | ** ** |       |   | 162 | ** ** |   | 162 |   |
| Property and  equipment, at cost, net       |       |                               | 50,063     | ** **          |       |                              | 29,858     | ** ** |       |   | 20,205 | ** ** |   | 31,600 |   |
| Intangible assets                           |       |                               | —     | ** **          |       |                              | —     | ** ** |       |   | — | ** ** |   | 26,800 |   |
| Other assets, net                           |       |                               | 194        | ** **          |       |                              | 89         | ** ** |       |   | 105 | ** ** |   | 105 |   |
| Total assets                                |       |                               | 53,896     | ** **          |       |                              | 33,424     | ** ** |       |   | 20,472 | ** ** |   | 58,667 |   |
| **LIABILITIES**                             | ** ** |                               | ** ** | ** **          |       |                              | ** ** | ** ** |       |   | ** ** | ** ** |   | ** ** | ** ** |
| Current liabilities:                        |       |                               |       | ** **          |       |                              |       | ** ** |       |   |   | ** ** |   |   |   |
| Accounts payable                            |       |                               | 5,048      | ** **          |       |                              | 4,372      | ** ** |       |   | 676 | ** ** |   | 676 |   |
| Accrued  liabilities                        |       |                               | 95         | ** **          |       |                              | 30         | ** ** |       |   | 65 | ** ** |   | 65 |   |
| Current  maturities of long term debt       |       |                               | 11,100     | ** **          |       |                              | 2,221      | ** ** |       |   | 8,879 | ** ** |   | 8,879 |   |
| Total current  liabilities                  |       |                               | 16,243     | ** **          |       |                              | 6,623      | ** ** |       |   | 9,620 | ** ** |   | 9,620 |   |
| Commitments and  contingencies              |       |                               | —     | ** **          |       |                              | —     | ** ** |       |   | — | ** ** |   | — |   |
| Long term debt,  net of current  maturities |       |                               | 24,253     | ** **          |       |                              | 24,253     | ** ** |       |   | — | ** ** |   | — |   |
| Asset retirement  obligation                |       |                               | 398        | ** **          |       |                              | —     | ** ** |       |   | 398 | ** ** |   | 398 |   |
| Total liabilities                           |       |                               | 40,894     | ** **          |       |                              | 30,876     | ** ** |       |   | 10,018 | ** ** |   | 10,018 |   |
| **NET  ASSETS**                             |       |                               | $          | 13,002              | ** ** |                              |       | $          | 2,548      | ** ** |   |   | $ | 10,454 | ** ** |   | $ | 48,649 |   |

 

In considerationfor the transfer:

*a.**               *Non-managing members received247,868 of our common units and 1,404,586 of our subordinated units.Immediately following the closing of the offering, 104,009 of the common unitswere redeemed for approximately $2.2 million.

*b.**               *The managing member of HilandPartners, LLC received 5,059 of our common units and 28,665 of our subordinatedunits, none of which were redeemed.

As a part of the transactions, owners of CGI, HilandPartners, LLC and certain members of our management received an aggregate of138,776 equivalent units of our General Partner, representing substantially allof the ownership of the general partner and a 2% equity ownership in us.

The proceeds of the publicoffering were used to: redeem an aggregate of 300,000 common units from formerowners 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 theremaining $2.2 million of expenses associated with the offering andformation transactions; pay $0.6 million of debt issuance costs related tothe credit facility; distribute $3.9 million to the former owners ofHiland Partners, LLC in reimbursement of certain 

F-22

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capitalizedexpenditures related to the assets of Hiland Partners, LLC that werecontributed to us; and replenish approximately $12.2 million of workingcapital.

**Note 3:   Acquisitions**

*KintaArea Gathering System.**  *OnMay 1, 2006, we acquired certain gas gathering assets from Enogex GasGathering, 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 partnerequivalent units to our general partner for proceeds of $35.0 million andborrowings of $61.2 million under our credit facility. We refer to these assetsas the Kinta Area gathering assets. Adetermination was made by our management of the fair value of these assets andliabilities as required by SFAS 141 “Business Combinations,” primarily usingcurrent replacement cost for the acquired gas gathering assets and relatedequipment less estimated accumulated depreciation on such replacement costs;and estimated discounted cash flows arising from future renegotiated customercontracts. The acquired assets at the time of the acquisition, which arelocated in the eastern Oklahoma Arkoma Basin, had approximately 672 wellheadreceipt points and included five separate low pressure natural gas gatheringsystems, which consisted of over 569 miles of natural gas gathering pipelinesand 23 compressors with an aggregate of approximately 40,000 horsepower. Thenatural gas gathering systems operate under contracts with producers thatprovide for services under fixed-fee arrangements. We operate the Kinta Areagathering assets substantially differently than were operated by the previousowner. Since there was no sufficient continuity of the Kinta Area gatheringassets’ operations prior to and after our acquisition, disclosure of priorfinancial information would not be material to an understanding of futureoperations. Therefore, the acquisition has been recorded as a purchase ofassets and not of a business and no pro forma financial information is requiredto be presented.

Thefollowing table presents the resulting allocation to the net assets acquiredand liabilities assumed on May 1, 2006:

| Pipelines,  including right of ways   |   | $      | 56,175 |   |
|---------------------------------------|--------|--------|--------|--------|
| Compressors                           |   | 22,221 |   |
| Other equipment  and buildings        |   | 8,618  |   |
| Customer  relationships               |   | 10,492 |   |
|                                  |   | 97,506 |   |
| Asset retirement  obligations assumed |   | 1,106  |   |
| Net assets acquired                   |   | $      | 96,400 |   |

 

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

*HilandPartners, LLC, (Bakken).*   On September 26,2005, we completed our acquisition of Hiland Partners, LLC, an Oklahomalimited liability company, for approximately $92.7 million in cash,$35.0 million of which was used to retire outstanding HilandPartners, LLC indebtedness. The effective date of the acquisition was September 1,2005. Hiland Partners, LLC’s principal asset was the Bakken gathering system locatedin Richland County, Montana. At the time of the acquisition, the Bakkengathering system consisted of approximately 256 miles of gas gatheringpipeline, a natural gas processing plant, two compressor stations, which werecomprised of three compressors with an aggregate of approximately 4,434horsepower, and one fractionation facility. The Bakken processing plant and aportion of the gathering system became operational on November 8, 2004. Tofacilitate the closing of the acquisition, we amended our senior securedrevolving credit facility to increase our borrowing capacity under the facilityfrom $55.0 million to $125.0 million, consisting of a$117.5 million acquisition facility and a $7.5 million workingcapital facility. We used a portion of this increased capacity to fund theacquisition.

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To theextent of our non-controlling ownership of Hiland Partners, LLC, theacquisition was accounted for using the purchase method of accounting underSFAS No. 141, “Business Combinations”. As of the date of our acquisition,Hiland Partners, LLC was an entity partially owned by an affiliate who, atthe time, was a controlling member of our general partner. Accordingly, 49% ofthe Bakken gathering system assets, for which estimated fair value was inexcess of historical basis, have been recorded at historical cost and 51% ofthe Bakken gathering system assets have been recorded at fair value. A cashdistribution of $27.8 million made to this affiliate, as reported as areduction of owners’ equity, reflects the difference in the purchase price paidto this affiliate and his cost basis in the net assets of HilandPartners, LLC. The fair value of the assets acquired has also been reducedby imputed interest expense from September 1, 2005, the effective date ofthe acquisition, through the closing date, September 26, 2005. Thefollowing table presents the resulting allocation to the net assets acquiredand liabilities assumed at the effective date of acquisition:

| Cash and cash  equivalents                                                                             |   | $      | 300    |   |
|--------------------------------------------------------------------------------------------------------|--------|--------|--------|--------|
| Accounts receivable                                                                                    |   | 3,708  |   |
| Other current assets                                                                                   |   | 20     |   |
| Property, plant and  equipment                                                                         |   | 49,873 |   |
| Customer contracts                                                                                     |   | 17,589 |   |
| Total assets acquired                                                                                  |   | 71,490 |   |
| Accounts payable                                                                                       |   | (6,217 | )      |
| Accrued liabilities                                                                                    |   | (125   | )      |
| Total liabilities  assumed                                                                             |   | (6,342 | )      |
| Net assets of Hiland  Partners, LLC                                                                    |   | 65,148 |   |
| Imputed interest expense                                                                               |   | (289   | )      |
| Purchase price of net assets of Hiland Partners, LLC  less distribution to the controlling member |   | $      | 64,859 |   |

 

The operations of theBakken gathering system are included in the statement of operations andstatement of cash flows from September 1, 2005 forward. The operations ofthe assets acquired from Hiland Partners, LLC in note 2 above are included inthe 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 consolidatedfinancial statements for the indicated periods with the following pro formaimpact on the consolidated combined statements of operations.

| ** **                                                      | ** ** | **For the Year Ended** | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                                      | ** ** | **December 31,**                 | ** ** |
| ** **                                                      | ** ** | **2005**                              | ** ** | **2004** | ** ** |
| Revenues as reported                                            |       | $                                     | 166,601    |   | $ | 98,296 |   |
| Revenues from acquired interests                                |       | 18,648                                |       | 14,335 |   |
| Pro forma revenues                                              |       | $                                     | 185,249    |   | $ | 112,631 |   |
| Net income as reported                                          |       | $                                     | 10,337     |   | $ | 4,912 |   |
| Loss from acquired interests                                    |       | (4,176                                | )          | (1,867 | ) |
| Pro forma net income                                            |       | 6,161                                 |       | $ | 3,045 |   |
| Less income attributable to predecessor                         |       | (493                                  | )          |   |   |
| Less general partner interest in pro forma net  income          |       | (378                                  | )          |   |   |
| Limited partners’ interest in pro forma net income         |       | $                                     | 5,290      |   |   |   |
| Proforma net income per limited partner unit—basic         |       | $                                     | 0.75       |   |   |   |
| Proforma net income per limited partner unit—diluted       |       | $                                     | 0.75       |   |   |   |
| Weighted average limited partner units outstanding—basic   |       | 7,034,000                             |       |   |   |
| Weighted average limited partner units outstanding—diluted |       | 7,086,000                             |       |   |   |

 

F-24

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**Note 4:   Property and Equipment**

| ** **                                       | ** ** | **As of**        | ** ** | **As of**        | ** ** |
|--------------------------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                                       | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
| ** **                                       | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| Land                                             |       |                  | $          | 255                   |       |   |   | $ | 225 |   |   |
| Construction in  progress                        |       |                  | 48,610     |                  |       |   | 3,676 |   |   |
| Midstream  pipeline, plants and compressors      |       |                  | 226,157    |                  |       |   | 122,927 |   |   |
| Compression and  water injection equipment       |       |                  | 19,270     |                  |       |   | 19,264 |   |   |
| Other                                            |       |                  | 2,471      |                  |       |   | 1,689 |   |   |
|                                             |       |                  | 296,763    |                  |       |   | 147,781 |   |   |
| Less: accumulated  depreciation and amortization |       |                  | 43,962     |                  |       |   | 27,066 |   |   |
|                                             |       |                  | $          | 252,801               |       |   |   | $ | 120,715 |   |   |

 

We capitalized interest of $1,467 and $32 during theyear ended December 31, 2006 and 2005, respectively.

Depreciation charged toexpense, including discontinued operations in 2004, totaled $16,954, $8,162,and $4,170 for the years ended December 31, 2006, 2005 and 2004, respectively.

**Note 5:   Derivatives**

We have entered into certain financial swapinstruments that are classified as cash flow hedges in accordance with SFAS No. 133,as amended, and relate to forecasted sales in 2006, 2007 and 2008. We enteredinto these instruments to hedge forecasted natural gas and NGL sales orpurchases against the variability in expected future cash flows attributable tochanges in commodity prices. Under all but one of these contractual swapagreements with our counterparties, we receive a fixed price and pay a floatingprice based on certain indices for the relevant contract period as theunderlying natural gas or NGL is sold. In one agreement, we pay a fixed priceand receive a floating price based on certain indices for the relevant contractperiod as the underlying natural gas is purchased.

We formally document all relationships between hedginginstruments and the items being hedged, including our risk management objectiveand strategy for undertaking the hedging transactions. This includes matchingthe natural gas and NGL futures, the “sold fixed for floating price” or “buyfixed for floating price” contracts, to the forecasted transactions. We assess,both at the inception of the hedge and on an ongoing basis, whether thederivatives are highly effective in offsetting changes in the fair value ofhedged items. Highly effective is deemed to be a correlation range from 80% to125% of the change in cash flows of the derivative in offsetting the cash flowsof the hedged transaction. If it is determined that a derivative is not highlyeffective as a hedge or it has ceased to be a highly effective hedge, due tothe loss of correlation between changes in natural gas or NGL reference pricesunder a hedging instrument and actual natural gas or NGL prices, we willdiscontinue hedge accounting for the derivative and subsequent changes in fairvalue for the derivative will be recognized immediately into earnings. Weassess effectiveness using regression analysis and ineffectiveness using thedollar offset method.

Derivativesare recorded on our consolidated balance sheet as assets or liabilities at fairvalue. For derivatives qualifying as hedges, the effective portion of changesin fair value are recognized in owners’ equity as accumulated othercomprehensive income and reclassified to earnings when the underlying hedgedphysical transaction closes. For non-qualifying derivatives and for theineffective portion of qualifying derivatives, changes in fair value arerecognized in earnings as they occur. Actual amounts that will be reclassifiedwill vary as a result of future changes in prices. Hedge ineffectiveness isrecorded in income while the hedge contract is open and may increase ordecrease until settlement of the contract. Realized cash gains and losses onclosed/settled instruments are reflected in the contract month being 

F-25

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hedged as an adjustment to our midstream revenue.During the year ended December 31, 2006 we reclassified net gains of$3,582 on closed/settled hedge transactions to midstream revenues out of othercomprehensive income and also recorded $6,889 to other comprehensive income forthe favorable change in fair value of open derivatives. During the year ended December 31,2006, we recorded gains of $113, on the ineffective portions of our qualifyingopen derivative transactions. At December 31, 2006, our accumulated othercomprehensive income related to derivatives was $4,356. Of this amount, weanticipate $2,755 will be reclassified to earnings during the next twelvemonths and $1,601 will be reclassified to earnings in subsequent periods. Wefirst entered into derivative transactions in October 2005 and had noclosed/settled hedge transactions or ineffective portions of qualifying openderivative transactions during the year ended December 31, 2005. The fairvalue of derivative assets and liabilities are as follows for the indicatedperiods:

| ** **                                           | ** ** | **As of**        | ** ** | **As of**        | ** ** |
|------------------------------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                                           | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
| ** **                                           | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| Fair value of  derivative assets—current        |       |                  | $          | 4,707                 |       |   |   | $ | 868 |   |   |
| Fair value of  derivative assets—long term      |       |                  | 1,955      |                  |       |   | 181 |   |   |
| Fair value of  derivative liabilities—current   |       |                  | (1,902     | )                     |       |   | — |   |   |
| Fair value of  derivative liabilities—long term |       |                  | (291       | )                     |       |   | — |   |   |
| Net fair value of  derivatives                       |       |                  | $          | 4,469                 |       |   |   | $ | 1,049 |   |   |

 

The terms of ourderivative contracts currently extend as far as December 2008. Ourcounterparty to all of our derivative contracts is BP Corporation North America, Inc.Set forth below is the summarized notional amount and terms of all instrumentsheld for price risk management purposes at December 31, 2006.

| ** **                                                        | ** ** | ** ** | ** ** | ** **   | ** ** | **Fair Value**  | ** ** |
|-------------------------------------------------------------------|------------|------------|------------|--------------|------------|----------------------|------------|
| ** **                                                        | ** ** | ** ** | ** ** | **Average**  | ** ** | **Asset**            | ** ** |
| **Description and Production Period**              | ** ** | ** ** | ** ** | **Volume**   | ** ** | **Fixed Price** | ** ** | **(Liability)** | ** ** |
| Natural Gas—Sold  Fixed for Floating Price Swaps             |       | (MMBtu)    |       | (per MMBtu)  |       |                 |       |   |   |
| January 2007  - December 2007                           |       | 1,620,000  |       |         | $          | 8.03                 |       |   |   | $ | 4,634 |   |   |
| January 2008  - December 2008                           |       | 1,620,000  |       |         | $          | 8.00                 |       |   |   | 1,955 |   |   |
|                                                              |       |       |       |         |       |                 |       |   | $ | 6,589 |   |   |
| Natural Gas—Buy Fixed for Floating Price Swaps               |       | (MMBtu)    |       | (per  MMBtu) |       |                 |       |   |   |
| January 2007  - December 2007                           |       | 600,000    |       |         | $          | 8.87                 |       |   |   | $ | (1,625 | ) |   |
| January 2008  - March 2008                              |       | 150,000    |       |         | $          | 8.87                 |       |   |   | (194 | ) |   |
|                                                              |       |       |       |         |       |                 |       |   | $ | (1,819 | ) |   |
| Natural Gas Liquids—Sold Fixed for Floating Price Swaps |       | (Bbls)     |       | (per Gallon) |       |                 |       |   |   |
| January 2007  - December 2007                           |       | 152,652    |       |         | $          | 1.13                 |       |   |   | $ | (204 | ) |   |
| January 2008  - March 2008                              |       | 38,163     |       |         | $          | 1.13                 |       |   |   | (97 | ) |   |
|                                                              |       |       |       |         |       |                 |       |   | $ | (301 | ) |   |
|                                                                   |            |            |            |              |            |                      |            |  |  |  |  |  |  |  |  |

 

**Note 6:   Long-Term Debt**

| ** **             | ** ** | **As of**        | ** ** | **As of**        | ** ** |
|------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **             | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
| ** **             | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| Note payable—bank |       |                  | $          | 147,064               |       |   |   | $ | 33,784 |   |   |
|                        |            |                       |            |                       |            |  |  |  |  |  |  |

 

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On February 15, 2005, concurrently with theclosing of our initial public offering, we entered into a three-year$55.0 million senior secured revolving credit facility. The creditfacility consisted of a $47.5 million senior secured revolving creditfacility to be used for funding acquisitions and other capital expenditures,issuance of letters of credit and general corporate purposes (the “revolvingacquisition facility”) and a $7.5 million senior secured revolving creditfacility to be used for working capital and to fund distributions (the “revolvingworking capital facility”).

On September 26, 2005, concurrently with theacquisition of Hiland Partners, LLC, we amended our credit facility toincrease our borrowing capacity under the facility from $55.0 million to$125.0 million, consisting of a $117.5 million acquisition facilityand a $7.5 million working capital facility. On the same date, we borrowed$93.7 million under the credit facility to acquire HilandPartners, LLC. We completed a follow on offering of our common units on November 21,2005 and used $65.2 million of the $66.1 million net proceeds to repay all but$28.5 million of the credit facility borrowings we had used to fund theacquisition.

On June 8, 2006, we entered into a secondamendment to our credit facility to, among other things, increase our borrowingbase to $200 million and revise certain covenants. The facility currentlyconsists of a $191.0 million senior secured revolving credit facility tobe used for funding acquisitions and other capital expenditures, issuance ofletters of credit and general corporate purposes (the “revolving acquisitionfacility”); and a $9.0 million senior secured revolving credit facility tobe used for working capital and to fund distributions (the “revolving workingcapital facility”).

In addition, our credit facility provides for anaccordion feature, which permits us, if certain conditions are met, to increasethe size of the revolving acquisition facility by up to an additional$150.0 million and allows for the issuance of letters of credit of up to$15.0 million in the aggregate. The credit facility will mature inMay 2011. At that time, the agreement will terminate and all outstandingamounts thereunder will be due and payable.

Our obligations under the credit facility are securedby 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 creditfacility.

Indebtedness under the credit facility bears interest,at our option, at either (i) an Alternate Base Rate plus an applicablemargin ranging from 50 to 125 basis points per annum or (ii) LIBOR plus anapplicable margin ranging from 150 to 225 basis points per annum based on ourratio of consolidated funded debt to EBITDA. The Alternate Base Rate is a rateper annum equal to the greatest of (a) the Prime Rate in effect on suchday, (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 aggregateamount of letters of credit issued under the credit facility at a percentageper annum equal to 1.0%. An unused commitment fee ranging from 25 to 50 basispoints per annum based on our ratio of consolidated funded debt to EBITDA willbe payable on the unused portion of the credit facility. During any step-upperiod, the applicable margin with respect to loans under the credit facilitywill be increased by 35 basis points per annum and the unused commitment feewill be increased by 12.5 basis points per annum.

The credit facility prohibits us from makingdistributions to unitholders if any default or event of default, as defined inthe credit facility, has occurred and is continuing or would result from thedistribution. In addition, the credit facility contains various covenants thatlimit, 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 itsbusiness, amend its material agreements, including the Omnibus Agreement, whichcontains non compete and indemnity provisions with affiliates, or enter into amerger, consolidation or sale of assets.

F-27

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The credit facility also contains covenants requiringus to maintain a maximum consolidated funded debt to EBITDA ratio of 4.0:1.0,provided that in the event we make certain permitted acquisitions or capitalexpenditures, the credit facility allows this ratio to increase to 4.75:1.0 forthe following three fiscal quarters (a “step-up period”) and a minimum interestcoverage ratio of 3.0:1.0.

The credit facility defines EBITDA as our consolidatednet income, plus income tax expense, interest expense, depreciation andamortization expense, amortization of intangibles and organizational costs,non-cash unit based compensation expense, and adjustments for non-cash gainsand losses on specified derivative transactions and for other extraordinaryitems.

Upon the occurrence of an event of default as definedin the credit facility, the lenders may, among other things, be able toaccelerate the maturity of the credit facility and exercise other rights andremedies as set forth in the credit facility.

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

As of December 31,2006, we had $147.1 million outstanding under the credit facility and werein compliance with its financial covenants.

**Note 7:   Commitmentsand Contingencies**

Wehave executed various natural gas fixed price physical forward sales contractson approximately 115,000 MMBtu per month for 2007 and 100,000 MMBtu per monthfor 2008 with fixed prices ranging from $4.49 to $9.13 per MMBtu in 2007 and$8.43 per MMBtu in 2008. These contracts have been designated as normal salesunder SFAS No. 133 and are therefore not marked to market as derivatives. Asummary of our fixed price physical forward sales contracts is presented in thetable below:

| ** **                              | ** ** | ** ** | ** ** | **Average**          | ** ** |
|-----------------------------------------|------------|------------|------------|----------------------|------------|
| ** **                              | ** ** | ** ** | ** ** | **Fixed Price** | ** ** |
| **Production period**              | ** ** | ** ** | ** ** | **(MMBtu)**          | ** ** | **(per MMBtu)** | ** ** |
| January 2007  - December 2007 |       | 1,380,000  |       |                 | $          | 6.92 |   |   |
| January 2008 - December 2008  |       | 1,200,000  |       |                 | $          | 8.43 |   |   |
|                                         |            |            |            |                      |            |  |  |  |  |  |

 

We maintain a defined contribution retirement plan forour employees under which we make discretionary contributions to the plan basedon a percentage of eligible employees’ compensation. Contributions to the planare 5.0% of eligible employees’ compensation and resulted in expenses for thethree years ended December 31, 2006, 2005 and 2004 of $201, $111 and $70,respectively.

We jointly participate with other affiliated companiesin a self-insurance pool (the “Pool”) covering health and workers’ compensationclaims made by employees up to the first $150 and $500, respectively, perclaim. Any amounts paid above these are reinsured through third partyproviders. Premiums charged to the Partnership are based on estimated costs peremployee of the Pool. Property and general liability insurance is maintainedthrough third-party providers with a $100 deductible on each policy.

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

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

We lease office space from a related entity (Note 9). Welease certain facilities, vehicles and equipment under operating leases, mostof which contain annual renewal options. For the years ended 2006, 2005 and2004, rent expense was $994, $224 and $198, respectively, under these leases.

On November 8, 2005, we entered into a new 15-yeardefinitive gas purchase agreement with CRI under which we will gather, treatand process additional natural gas, which is produced as a by-product of CRI’ssecondary oil recovery operations. In order to fulfill our obligations underthe agreement, we are expanding our Badlands gas gathering system andprocessing. This expansion project includes the construction of a 40,000 Mcf/dnitrogen rejection plant and the expansion of our existing Badlandsfield-gathering infrastructure. We intend to invest approximately$40.0 million in the expansion project by the second quarter of 2007, ofwhich approximately $31.7 million had been invested as of December 31,2006. We plan to invest an additional $9.5 million during the second half of2007 to expand the system.

We are in the process of installing fouramine-treating facilities at several of our Kinta Area gathering systemlocations to remove excess carbon dioxide levels from the natural gas. We arealso installing additional compression facilities to expand the currentcapacity by approximately 8,000 Mcf/d on these gathering systems. We will invest approximately $6.0 millionon these projects and expect that all of the projects will be completed by theend of the first quarter of 2007.

Asummary of our contractual cash obligations as of December 31, 2006,including obligations related to the Badlands and Kinta Area projects, minimumfuture rental commitments under operating leases having non-cancelable leaseterms in excess of one year, and leases renewed and entered into subsequent toyear end but prior to financial statement issuance, is presented below:

| ** **                                | ** ** | **Payment Due by Period** | ** ** |
|-------------------------------------------|------------|------------------------------------------|------------|
| ** **                                | ** ** | **Total**                                | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | **Due in** | ** ** | ** ** | ** ** |
| **Type of Obligation**          | ** ** | ** **                               | ** ** | **Obligation** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** |
| ** **                                | ** ** | **(in thousands)**                  | ** ** |
| Senior secured  revolving credit facility |       | $                                        | 147,064    |   | $ | — |   |   | $ | — |   |   |   | $ | — |   |   |   | $ | — |   |   | $ | 147,064 |   |   | $ | — |   |   |
| Contracts on  internal expansion projects |       | 12,532                                   |       | 11,203 |   |   | 326 |   |   |   | 325 |   |   |   | 326 |   |   | 325 |   |   | 27 |   |   |
| Operating leases  and service  agreements |       | 1,423                                    |       | 774 |   |   | 278 |   |   |   | 138 |   |   |   | 83 |   |   | 49 |   |   | 101 |   |   |
| Total contractual cash obligations        |       | $                                        | 161,019    |   | $ | 11,977 |   |   | $ | 604 |   |   |   | $ | 463 |   |   |   | $ | 409 |   |   | $ | 147,438 |   |   | $ | 128 |   |   |
|                                           |            |                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

F-29

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**Note 8:   SignificantCustomers and Suppliers**

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

| ** ** | ** ** | **For the Year ended December 31,** | ** ** |
|------------|------------|--------------------------------------------------------------|------------|
| ** ** | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| Customer 1 |       |                                                         | 20         | % |   |   | 16 | % |   |   | 29 | % |   |
| Customer 2 |       |                                                         | 15         | % |   |   | — |   |   |   | — |   |   |
| Customer 3 |       |                                                         | 14         | % |   |   | 6 | % |   |   | — |   |   |
| Customer 4 |       |                                                         | 13         | % |   |   | 13 | % |   |   | 33 | % |   |
| Customer 5 |       |                                                         | 11         | % |   |   | 4 | % |   |   | — |   |   |
| Customer 6 |       |                                                         | 8          | % |   |   | 8 | % |   |   | 10 | % |   |
| Customer 7 |       |                                                         | 4          | % |   |   | 23 | % |   |   | — |   |   |

 

All ofour purchases are from domestic sources. The following table presents our topmidstream suppliers as a percent of total midstream purchases for the periodsindicated:

| ** **                       | ** ** | **For the Year ended December 31,** | ** ** |
|----------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                       | ** ** | **2006**                                                     | ** ** | **2005** | ** ** | **2004** | ** ** |
| Supplier 1  (affiliated company) |       |                                                         | 32         | % |   |   | 34 | % |   |   | 33 | % |   |
| Supplier 2                       |       |                                                         | 24         | % |   |   | 28 | % |   |   | 33 | % |   |
| Supplier 3                       |       |                                                         | 13         | % |   |   | 6 | % |   |   | — |   |   |
| Supplier 4                       |       |                                                         | 6          | % |   |   | 13 | % |   |   | 17 | % |   |
| Supplier 5                       |       |                                                         | 4          | % |   |   | 2 | % |   |   | — |   |   |

 

**Note 9:   RelatedParty Transactions**

We purchase natural gas and NGLs from affiliatedcompanies. Purchases of product from affiliates totaled $50.3 million,$45.8 million, and $27.6 million for the years ended December 31,2006, 2005 and 2004, respectively. We sell natural gas and NGLs to affiliatedcompanies. Sales of product to affiliates totaled $4.1 million,$5.2 million, and $3.3 million for the years ended December 31,2006, 2005 and 2004, respectively. Compression revenues from affiliates were$4.8 million and $4.2 million for the years ended December 31, 2006and 2005, respectively. There were no compression revenues in 2004.

Accounts receivable-affiliates of $1,284 and $1,523 atDecember 31, 2006 and 2005, respectively, includes $1,260 and $1,451 fromone affiliate for midstream sales.

Accounts payable-affiliates of $4,412 and $6,122 at December 31,2006 and 2005, respectively, includes $3,819 and $5,684 due to one affiliatefor midstream purchases. Accounts payable-affiliates of $2,998 at December 31,2004 is all payable to one affiliate for midstream purchases.

We utilize affiliated companies to provide services toour plants and pipelines and certain administrative costs. The total amountpaid to these companies was $353, $336, and $183 during the years ended December 31,2006, 2005 and 2004, respectively.

We lease office spaceunder operating leases directly or indirectly from an affiliate. Rents paidassociated with these leases totaled $118, $75, and $51 for the years ended December 31,2006, 2005 and 2004, respectively.

**Note 10:   ReportableSegments**

On February 15, 2005, certain assets andliabilities of Hiland Partners, LLC were contributed to us in conjunction withour initial public offering. As a result of this transaction, we have distinctoperating 

F-30

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segments for which additionalfinancial information must be reported. Prior to February 15, 2005, we didnot have operating segments. Our operations are now classified into tworeportable segments:

(1)   Midstream, which is thegathering, compressing, dehydrating, treating and processing of natural gas andfractionating NGLs.

(2)   Compression, which is providingair compression and water injection services for CRI’s oil and gas secondaryrecovery operations that are ongoing in North Dakota.

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

Midstream assets totaled $312,431 and $158,295 at December 31,2006 and 2005, respectively. On the same dates, assets attributable tocompression operations totaled $31,385 and $34,894, respectively. All but $72of the total additions to property and equipment of $62,137 and Kinta Areagathering assets acquired of $96,400 for the year ended December 31, 2006was attributable to midstream operations. Capital expenditures of $10,389 forthe year ended December 31, 2005 were entirely related to the midstreamsegment. We had no compression segment prior to February 15, 2005.

Thetable below presents information about operating income for the reportablesegments for the years ended December 31, 2006 and 2005.

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

 

**Note 11:   DiscontinuedOperations**

During the first quarter of 2004, the Partnershipdetermined it would no longer pursue its interests in direct production of oiland gas. Amounts for oil and gas income and expense are presented in thesestatements as discontinued operations. Effective May 31, 2004, thePartnership transferred all its interests in its oil and gas properties to CRI.

F-31

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Asummary of oil and gas operations discontinued during the year ended December 31,2004 is presented below:

| Revenues                       |   | $    | 266 |   |
|--------------------------------|--------|------|-----|--------|
| Expenses                       |   | (165 | )   |
| Depreciation and  amortization |   | (66  | )   |
| Net income                     |   | $    | 35  |   |

 

The May 31,2004 transfer, recorded at carrying value, included the following:

| Leasehold costs               |   | $      | 67     |   |
|-------------------------------|--------|--------|--------|--------|
| Capitalized  intangible costs |   | 3,063  |   |
| Lease and well  equipment     |   | 1,689  |   |
| Asset retirement  cost        |   | 41     |   |
| Accounts payable              |   | (298   | )      |
| Accumulated  amortization     |   | (1,623 | )      |
| Accumulated  depreciation     |   | (748   | )      |
| Asset retirement  obligation  |   | (50    | )      |
|                          |   | $      | 2,141  |   |

 

The Partnership followedthe “successful efforts” method of accounting for its oil and gas properties.Under the successful efforts method, costs of acquiring undeveloped oil and gasleasehold acreage, including lease bonuses, brokers’ fees and other relatedcosts are capitalized. Provisions for impairment of undeveloped oil and gasleases are based on periodic evaluations. Annual lease rentals and explorationexpenses, including geological and geophysical expenses and exploratory dryhole costs, are charged against income as incurred. Costs of drilling andequipping productive wells, including development dry holes and relatedproduction facilities, are capitalized. Depreciation and depletion of oil andgas production equipment and properties are determined under theunit-of-production method based on estimated proved recoverable oil and gasreserves.

**Note 12:   SelectedQuarterly Financial Data—Unaudited**

Thefollowing is a summary of selected quarterly financial data for the years endedDecember 31, 2006 and 2005.

| ** **                                        | ** ** | **2006 Quarter** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **1st**               | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** | ** ** |
| Revenues                                          |       | $                     | 53,409     |   | $ | 52,739 |   | $ | 57,267 |   | $ | 56,271 |   |
| Operating income                                  |       | 4,133                 |       | 5,174 |   | 5,539 |   | 5,452 |   |
| Net income                                        |       | 3,550                 |       | 3,818 |   | 3,738 |   | 3,576 |   |
| General partner  interest in net income           |       | 386                   |       | 491 |   | 712 |   | 820 |   |
| Limited partners’  interest in net income    |       | $                     | 3,164      |   | $ | 3,327 |   | $ | 3,026 |   | $ | 2,756 |   |
| Net income per  limited partner unit—basic   |       | $                     | 0.37       |   | $ | 0.37 |   | $ | 0.33 |   | $ | 0.30 |   |
| Net income per limited  partner unit—diluted |       | $                     | 0.37       |   | $ | 0.37 |   | $ | 0.33 |   | $ | 0.29 |   |

 

F-32

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| ** **                                        | ** ** | **2005 Quarter** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **1st**               | ** ** | **2nd** | ** ** | **3rd** | ** ** | **4th** | ** ** |
| Revenues                                          |       | $                     | 25,778     |   | $ | 30,603 |   | $ | 41,925 |   | $ | 68,295 |   |
| Operating income                                  |       | 1,968                 |       | 1,962 |   | 3,282 |   | 5,359 |   |
| Net income                                        |       | 1,636                 |       | 1,879 |   | 2,684 |   | 4,138 |   |
| Income  attributable to predecessor               |       | 493                   |       | — |   | — |   | — |   |
| General partner  interest in net income           |       | 23                    |       | 37 |   | 67 |   | 337 |   |
| Limited partners’  interest in net income    |       | $                     | 1,120      |   | $ | 1,842 |   | $ | 2,617 |   | $ | 3,801 |   |
| Net income per  limited partner unit—basic   |       | $                     | 0.16       |   | $ | 0.27 |   | $ | 0.38 |   | $ | 0.51 |   |
| Net income per limited  partner unit—diluted |       | $                     | 0.16       |   | $ | 0.27 |   | $ | 0.38 |   | $ | 0.50 |   |

 

**Note 13:**   NetIncome per Limited Partners’ Unit

Thecomputation of net income per limited partners’ unit is based on theweighted-average number of common and subordinated units outstanding during theperiod. Net income per unit applicable to limited partners is computed bydividing net income applicable to limited partners, after deducting the generalpartner’s 2% interest and incentive distributions, and after deducting netincome attributable to the Predecessor (before February 15, 2005), by theweighted-average number of limited partnership units outstanding. The followingis a reconciliation of the limited partner units used in the calculations ofincome per limited partner unit—basic and income per limited partner unit—dilutedassuming dilution for the years ended December 31, 2006 and 2005:
|                                                                 | ** ** | **2006**              | ** ** | **2005**               | ** ** |
|-----------------------------------------------------------------|------------|-----------------------|------------|------------------------|------------|
| ** **                                                      | ** ** | **Income**            | ** ** | ** **             | ** ** | ** ** | ** ** | **Income** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                      | ** ** | **Available to** | ** ** | ** **             | ** ** | ** ** | ** ** | **Available to** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                      | ** ** | **Limited**           | ** ** | **Limited**            | ** ** | ** ** | ** ** | **Limited** | ** ** | **Limited** | ** ** | ** ** | ** ** |
| ** **                                                      | ** ** | **Partners**          | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** | **Partners** | ** ** | **Partner Units** | ** ** | **Per Unit** | ** ** |
| ** **                                                      | ** ** | **(Numerator)**       | ** ** | **(Denominator)**      | ** ** | **Amount** | ** ** | **(Numerator)** | ** ** | **(Denominator)** | ** ** | **Amount** | ** ** |
| Income per limited  partner unit—basic:                    |       |                  |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Income available to limited unitholders                         |       |                  | $          | 12,273                 |       |   |   |   |   |   |   | $ | 1.37 |   |   |   | $ | 9,380 |   |   |   |   |   |   |   | $ | 1.33 |   |   |
| Weighted average limited partner units outstanding              |       |                  |       |                   |       |   | 8,961,000 |   |   |   |   |   |   |   |   |   |   |   | 7,034,000 |   |   |   |   |   |   |
| Income per limited  partner unit—diluted:                  |       |                  |       |                   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Unit options                                                    |       |                  |       |                   |       |   | 49,000 |   |   |   |   |   |   |   |   |   |   |   | 52,000 |   |   |   |   |   |   |
| Income available  to common unitholdersplus assumed conversions |       |                  | $          | 12,273                 |       |   |   | 9,010,000 |   |   |   | $ | 1.36 |   |   |   | $ | 9,380 |   |   |   | 7,086,000 |   |   |   | $ | 1.32 |   |   |

 

**Note 14:   Partners’Capital and Cash Distributions**

Our unitholders (limited partners) have only limitedvoting rights on matters affecting our operations and activities and,therefore, limited ability to influence our management’s decisions regardingour business. Unitholders did not select our general partner or elect the boardof directors of our general partner and effectively have no right to select ourgeneral partner or elect its board of directors in the future. Unitholders’voting rights are further restricted by our partnership agreement provisionproviding that any units held by a person that owns 20% or more of any class ofunits then outstanding, other than the general partner, its affiliates, theirtransferees and persons who acquired such units with the prior approval of theboard of directors of our general partner, cannot be voted on any matter. Inaddition, our partnership agreement contains provisions limiting the ability ofour unitholders to call meetings or to acquire information about our operations,as well as other provisions limiting a unitholders’ ability to influence themanner or direction of our management.

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Our PartnershipAgreement requires that we distribute all of our cash on hand at the end ofeach quarter, less reserves established at our general partner’s discretion. Werefer to this as “available cash.” The amount of available cash may be greaterthan or less than the minimum quarterly distributions. In general, we will payany cash distribution made each quarter in the following manner:

·       first, 98% to the commonunits and 2% to our general partner, until each common unit has received aminimum quarterly distribution of $0.45 plus any arrearages from priorquarters;

·       second, 98% to thesubordinated units and 2% to our general partner, until each subordinated unithas received a minimum quarterly distribution of $0.45; and

·       third, 98% to all units prorata, and 2% to our general partner, until each unit has received adistribution of $0.495.

If cash distributions per unit exceed $0.495 in anyquarter, our general partner will receive increasing percentages, up to amaximum of 50% of the cash we distribute in excess of that amount. We refer tothese distributions as “incentive distributions.”

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

Alldistributions paid by us to common and subordinated unitholders, includingamounts paid to affiliate owners and regular and incentive distributions paidto our general partner were as follows (in thousands, except per unit amounts):

| **Date Cash** | ** ** | **Per Unit Cash** | ** ** | ** ** | ** ** | ** **       | ** ** | ** **               | ** ** | ** **          | ** ** | ** **    | ** ** |
|--------------------|------------|-----------------------------|------------|------------|------------|------------------|------------|--------------------------|------------|---------------------|------------|---------------|------------|
| **Distribution**   | ** ** | **Distribution**            | ** ** | **Common** | ** ** | **Subordinated** | ** ** | **General Partner** | ** ** | **Total Cash** | ** ** |
| **Paid**           | ** ** | ** **                  | ** ** | **Amount** | ** ** | **Units**        | ** ** | **Units**                | ** ** | **Regular**         | ** ** | **Incentive** | ** ** | **Distribution** | ** ** |
| 05/13/05           |       |                        | $          | 0.2250     |       |             | $          | 612                      |       |                | $          | 918           |       |   |   | $ | 31 |   |   |   | $ | — |   |   |   | $ | 1,561 |   |   |
| 08/12/05           |       |                        | 0.4625     |       |       | 1,258            |       |                     | 1,887      |                |       |          | 64         |   |   |   | — |   |   |   | 3,209 |   |   |
| 11/14/05           |       |                        | 0.5125     |       |       | 1,398            |       |                     | 2,091      |                |       |          | 72         |   |   |   | 18 |   |   |   | 3,579 |   |   |
| 02/14/06           |       |                        | 0.6250     |       |       | 2,724            |       |                     | 2,550      |                |       |          | 112        |   |   |   | 249 |   |   |   | 5,635 |   |   |
| 05/15/06           |       |                        | 0.6500     |       |       | 2,858            |       |                     | 2,652      |                |       |          | 119        |   |   |   | 315 |   |   |   | 5,944 |   |   |
| 08/14/06           |       |                        | 0.6750     |       |       | 3,485            |       |                     | 2,754      |                |       |          | 136        |   |   |   | 414 |   |   |   | 6,789 |   |   |
| 11/14/06           |       |                        | 0.7000     |       |       | 3,623            |       |                     | 2,856      |                |       |          | 145        |   |   |   | 637 |   |   |   | 7,261 |   |   |
| 02/14/07(a)        |       |                        | 0.7125     |       |       | 3,694            |       |                     | 2,907      |                |       |          | 150        |   |   |   | 749 |   |   |   | 7,500 |   |   |
|               |       |                        | $          | 4.5625     |       |             | $          | 19,652                   |       |                | $          | 18,615        |       |   |   | $ | 829 |   |   |   | $ | 2,382 |   |   |   | $ | 41,478 |   |   |
|                    |            |                             |            |            |            |                  |            |                          |            |                     |            |               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(a)           Thiscash distribution was announced on January 25, 2007 and was paid on February 14,2007 to all unitholders of record as of February 5, 2007.

**Note 15:   SubsequentEvent (unaudited)**

On January 23, 2007 we, along with HilandPartners Finance Corp., our wholly owned subsidiary, filed an S-3/Aregistration statement with the Securities and Exchange Commission to registerunit and debt securities with a maximum aggregate offering price of $500,000.The securities we may offer include common units representing limitedpartnership interests in us; and debt securities, which may be either seniordebt securities or subordinated debt securities.

F-34

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